exv99w1

Exhibit 99.1

, 2008

Dear Entergy Corporation Shareholder:

I am pleased to inform you that on , 2008, the board of directors of Entergy Corporation (“Entergy”) approved the distribution of all the shares of common stock of Enexus Energy Corporation (“Enexus Energy”), a wholly-owned subsidiary of Entergy, to Entergy shareholders. Enexus Energy holds or will hold certain of the assets and liabilities associated with Entergy’s non-utility nuclear business.

This distribution is to be made pursuant to a plan initially approved by the board of directors of Entergy on November 3, 2007 (i) to separate Entergy’s non-utility nuclear business from the rest of Entergy’s businesses and (ii) for Entergy and Enexus Energy to enter into a nuclear services joint venture immediately prior to the separation. Upon the distribution, Entergy shareholders will own 100% of the common stock of Enexus Energy. In addition, Entergy and Enexus Energy will each own 50% of a joint venture called EquaGen LLC, which will operate Enexus Energy’s plants. Entergy’s board of directors believes that creating a separate non-utility nuclear company will increase value to, and is in the best interests of, our shareholders.

The distribution of Enexus Energy common stock will occur on , 2008 by way of a pro rata dividend to Entergy shareholders of record on , 2008, the record date of the distribution. Each Entergy shareholder will be entitled to receive share(s) of Enexus Energy common stock for each share of Entergy common stock held by such shareholder at the close of business on the record date. Enexus Energy common stock will be issued in book-entry form only, which means that no physical stock certificates will be issued. No fractional shares of Enexus Energy common stock will be issued. If you would otherwise have been entitled to a fractional share of Enexus Energy common stock in the distribution, you will receive the cash value of such fractional share instead. Shareholder approval of the distribution is not required, and you are not required to take any action to receive your Enexus Energy common stock. The distribution is intended to be tax-free to Entergy shareholders, except for cash received in lieu of any fractional share interests.

Following the distribution, you will own shares in both Entergy and Enexus Energy. The number of Entergy shares you own will not change as a result of this distribution. Entergy’s common stock will continue to trade on the New York Stock Exchange and the Chicago Stock Exchange under the symbol “ETR.” We intend to apply to have Enexus Energy’s common stock listed on the New York Stock Exchange under the ticker symbol .

The information statement, which is being mailed to all holders of Entergy common stock on the record date for the distribution, describes the distribution in detail and contains important information about Enexus Energy, its business, financial condition and operations. We urge you to read the information statement carefully. You are not required to take any specific action.

We want to thank you for your continued support of Entergy and we look forward to your future support of Enexus Energy.

Sincerely,

J. Wayne Leonard
Chairman of the Board and Chief Executive Officer

, 2008

Dear Future Enexus Energy Corporation Shareholder:

It is our pleasure to welcome you as a future shareholder of our company, Enexus Energy Corporation (“Enexus Energy”). We are excited about our future as one of the largest nuclear power generators in the United States.

We are a nuclear generating company with a strong operational track record and the necessary scale to operate as an independent generating company. We own six operating nuclear power plants located in the Northeast United States and Michigan and sell the electric power generated by those plants primarily to wholesale customers. Our 50/50 joint venture with Entergy Corporation, which will be called EquaGen LLC, will operate and provide services to our six operating nuclear power plants. We also offer, or expect to offer, operations, management and decommissioning services to nuclear power plants owned by other third-parties in the United States. Additionally, we believe we will be a leader in every aspect of the nuclear life cycle, including operations, license renewals, decommissioning estimates, acquisitions and dry fuel installations.

For the year ended December 31, 2007, we generated operating revenues of approximately $2.0 billion, operating income of approximately $714 million and net income of approximately $486 million.

We intend to apply to have our common stock listed on the New York Stock Exchange under the ticker symbol .

We invite you to learn more about Enexus Energy by reviewing the enclosed information statement. We urge you to read the information statement carefully. We look forward to our future and to your support as a holder of Enexus Energy common stock.

Sincerely,

Richard J. Smith
Chief Executive Officer

Preliminary Information Statement

(Subject to Completion, Dated May 12, 2008)

Information Statement

Distribution

ENTERGY CORPORATION

to Entergy Corporation Shareholders of

Common Stock of

ENEXUS ENERGY CORPORATION

This information statement is being furnished in connection with the distribution by Entergy Corporation, a Delaware corporation (“Entergy”), to its shareholders of all of the shares of common stock, par value $0.01 per share, of Enexus Energy Corporation, a Delaware corporation (“Enexus Energy”). Currently we are a wholly-owned subsidiary of Entergy that holds or will hold certain of the assets and liabilities associated with Entergy’s non-utility nuclear business. To implement the distribution, Entergy will distribute all of the shares of our common stock on a pro rata basis to the holders of Entergy common stock as of , 2008, the record date for the distribution. Each of you, as a holder of Entergy common stock, will receive share(s) of Enexus Energy common stock for each share of Entergy common stock that you held at the close of business on the record date for the distribution. The distribution will be made on , 2008. Immediately after the distribution is completed, Enexus Energy will be a separate, publicly-traded company.

No vote of Entergy shareholders is required in connection with this distribution. We are not asking you for a proxy, and you are requested not to send us a proxy.

No consideration is to be paid by Entergy shareholders in connection with this distribution. Entergy shareholders will not be required to pay any consideration for the shares of our common stock they receive in the distribution, and they will not be required to surrender or exchange shares of their Entergy common stock or take any other action in connection with the distribution. The number of shares of Entergy common stock owned by you will not change as a result of the distribution.

All of the outstanding shares of our common stock currently are owned by Entergy. Accordingly, there currently is no public trading market for our common stock. We intend to file an application to list our common stock on the New York Stock Exchange under the ticker symbol . Assuming that our common stock is approved for listing on the New York Stock Exchange, we anticipate that a limited market, commonly known as a “when-issued” trading market, for our common stock will develop on or shortly before the record date for the distribution and will continue up to and through the distribution date, and we anticipate that “regular-way” trading of our common stock will begin on the first trading day following the distribution date.

In reviewing this information statement, you should carefully consider the matters described under the caption “Risk Factors” beginning on page 21 of this information statement.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of any of the securities of Enexus Energy, or determined whether this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement does not constitute an offer to sell or the solicitation of an offer to buy any securities.

The date of this information statement is , 2008.

This information statement was first mailed to Entergy shareholders on or about , 2008.

TABLE OF CONTENTS


Summary			3
Risk Factors			21
Forward-Looking Statements			37
The Separation			39
Dividend Policy			50
Capitalization			51
Unaudited Pro Forma Financial Information of Enexus Energy			52
Selected Historical Combined Financial Data			57
Management’s Discussion and Analysis of Results of Operations and Financial Condition			58
Our Industry			75
Business			82
Environmental Matters			93
Employees, Properties and Facilities, Government Regulation and Legal Proceedings			97
Management			105
Compensation Discussion and Analysis			106
Executive Compensation			121
Security Ownership of Certain Beneficial Owners and Management			135
Certain Relationships and Related Party Transactions			136
Description of Enexus Energy Stock			147
Description of Material Indebtedness			151
Where You Can Find More Information			152
Index to Financial Statements			F-1
Report of Independent Registered Public Accounting Firm and Financial Statements of Enexus Energy			F-2

TRADEMARKS, TRADE NAMES AND SERVICE MARKS

Certain trademarks, trade names and logos of third parties may appear in this information statement. The display of such third parties’ trademarks, trade names and logos is for informational purposes only, and is not intended for marketing or promotional purposes or as an endorsement of their business or of any of their products or services.

MARKET AND INDUSTRY DATA AND FORECASTS

This information statement includes industry data and forecasts that we have prepared based, in part, upon industry data and forecasts obtained from industry publications, surveys and publicly-available websites. Third party industry publications and surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. The statements regarding, for example, our industry, industry trends and our industry position in this information statement are based on information derived from market studies, research reports and publicly-available websites.

iii

DEFINITIONS

Certain abbreviations or acronyms used in the text and notes are defined below:


Abbreviation or Acronym		Term

Average Price Realized per MWh		As reported revenue per MWh billed for all non-utility nuclear operation
BTU		British Thermal Unit
capacity factor		Actual plant output divided by maximum potential plant output for the period
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CO₂		Carbon dioxide
Code		Internal Revenue Code
DOE		United States Department of Energy
EITF		Financial Accounting Standards Board’s Emerging Issues Task Force
Entergy		Entergy Corporation and its direct and indirect subsidiaries
EPA		United States Environmental Protection Agency
FASB		Financial Accounting Standards Board
FCA		Forward capacity auction
FCM		Forward capacity market
FEMA		Federal Emergency Management Agency
FERC		Federal Energy Regulatory Commission
firm liquidated damages		Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset); if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in the contract
FitzPatrick		James A. FitzPatrick nuclear power plant, located in Oswego County, New York
forced outage rate		A measure of lost production due to unplanned unit outages
FSP		FASB Staff Position
GW		Gigawatt
GWh billed		Total number of GWh billed to all customers
Indian Point 2		Indian Point Energy Center Unit 2 nuclear power plant, located in Westchester County, New York
Indian Point 3		Indian Point Energy Center Unit 3 nuclear power plant, located in Westchester County, New York
Indian Point Energy Center		Indian Point Energy Center Unit 2 and Unit 3
installed capacity		The optimal output, measured in MW, of a nuclear power plant when the plant is operating at its design conditions
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		ISO New England, the market into which Vermont Yankee and Pilgrim sell power
Joint Venture Agreements		Refers to both the Formation Agreement and the Limited Liability Company Agreement of EquaGen LLC
kW		Kilowatt
kWh		Kilowatt-hour(s)
LSE		Load serving entity
MISO		Midwest ISO, the market into which Palisades sells power
MMBtu		One million British Thermal Units
MW		Megawatt(s), which equals one thousand kilowatt(s)
MWh		Megawatt-hour(s)
NEIL		Nuclear Electric Insurance Limited


NERC		North American Electric Reliability Corporation, a self-regulatory organization, overseen by the FERC, that was formed in 1968 by the electric utility industry to promote the reliability and adequacy of bulk power supply
net MW in operation		Installed capacity owned and operated
net revenue		Operating revenues less fuel and fuel-related expenses
New York Rest of State		The regions, other than New York City, that are administered by the NYISO
NO_x		Mono-nitrogen oxides (NO and NO₂)
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NYDEC		New York State Department of Environmental Conservation
NYISO		New York ISO, the market into which Indian Point 2, Indian Point 3 and FitzPatrick sell power
NYPA		New York Power Authority
NYPSC		New York State Public Service Commission
Operating Agreements		Refers collectively to each operating agreement between each wholly-owned subsidiary that owns our nuclear power plants and Entergy Nuclear Operations, Inc. to be entered into in connection with the separation
Palisades		Palisades power plant, located in Covert, Michigan
peak load		The amount of power required to supply customers at times when the need is greatest
Pilgrim		Pilgrim Nuclear Station nuclear power plant, located near Plymouth, Massachusetts
PPA		Purchased power agreement
PRP		Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUHCA 2005		Public Utility Holding Company Act of 2005, which repealed the Public Utility Holding Company Act of 1935
Refueling outage duration		Number of days lost for scheduled refueling outage during the period
RGGI		Regional Greenhouse Gas Initiative
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards as promulgated by the FASB
Shared Services Agreements		Refers collectively to the services agreements between EquaGen LLC and certain subsidiaries of Entergy to be entered into in connection with the separation
SO₂		Sulfur dioxide
TWh		Terawatt-hour(s), which equals one billion kilowatt-hours
unforced capacity		Unforced capacity is the percentage of installed capacity available after a unit’s forced outage rate is calculated
unit-contingent		Transaction under which power is supplied from a specific generation asset; if the asset is unavailable, the seller is not liable to the buyer for any damages
unit-contingent with guarantee of availability		Provides for payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold
VANR		Vermont Agency of Natural Resources
Vermont Yankee		Vermont Yankee nuclear power plant, located in Vernon, Vermont

SUMMARY

This summary highlights selected information from this information statement relating to our company, our separation from Entergy and the distribution of our common stock by Entergy to its shareholders. For a more complete understanding of our business and the separation and distribution, you should carefully read the entire information statement.

Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. Except as otherwise indicated or unless the context otherwise requires, “Enexus Energy,” “we,” “us,” “our” and “our company” refer to Enexus Energy Corporation and its consolidated subsidiaries, including EquaGen LLC; “EquaGen” refers to EquaGen LLC and its consolidated subsidiaries, a joint venture with equal ownership between us and Entergy; “our business” refers to our business as will be conducted by Enexus Energy; and “Entergy Nuclear Operations” refers to Entergy Nuclear Operations, Inc. which, after the separation will change its name to EquaGen Nuclear LLC and will become a subsidiary of EquaGen LLC. Unless otherwise indicated, information is presented as of May 12, 2008.

Our Company

We own six operating nuclear power plants, five of which are located in the Northeast United States, with the sixth located in Michigan. Our nuclear power plants have nearly 5,000 MW of electric generation capacity and we are primarily focused on selling the power produced by those plants to wholesale customers. Our strategy is focused on providing safe and reliable electric power to our customers, while taking advantage of market trends and strategic investments that are consistent with our core values and value enhancing for our shareholders. We are the only publicly-traded, virtually emissions-free, nuclear generating company in the United States and it is our belief that nuclear power is an important part of solving the problems of global climate change and energy independence.

The Northeast United States is a region that is experiencing a combination of high natural gas prices and constraints on the growth of supply, a dynamic that we believe has contributed to power prices that are among the highest in the country. Due to these factors, as well as potential carbon dioxide legislation, we expect power prices in the Northeast to remain high over the next several years, providing us the opportunity to realize growth in our revenues and operating income.

We will operate and maintain our nuclear power plants through EquaGen, in which we hold a 50% ownership interest. Entergy Nuclear Operations, which will become a subsidiary of EquaGen immediately prior to the separation, will be responsible for (i) operating and making capital improvements to each nuclear power plant, and (ii) complying with permits and approvals, applicable laws and regulations, the applicable NRC operating license and the budgets approved by us for each plant all in accordance with the Operating Agreement for each plant. We also offer, or expect to offer, operations, management and decommissioning services to nuclear power plants owned by other third-parties in the United States. Through EquaGen, we believe we have a strong track record of maintaining, improving and safely operating nuclear power plants. Additionally, we believe we will be a leader in every aspect of the nuclear life cycle, including operations, license renewals, decommissioning estimates, acquisitions and dry fuel installations.

For the year ended December 31, 2007, we generated operating revenues of approximately $2.0 billion, operating income of approximately $714 million and net income of approximately $486 million.

Our headquarters are located at , Jackson, Mississippi and our general telephone number is . We maintain an Internet site at http://www.enexusenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this information statement.

Our Strengths

We believe that we are well positioned to execute our business successfully because of the following competitive strengths:


	•	We have a strong track record of safety and security, and a reputation as a strong nuclear operator with fleet capability factors in the top quartile of the industry. We have achieved positive results in periodic evaluations of the safety and security at our nuclear power plants, and we have a proven track record as a strong nuclear operator with repeated success in acquiring underperforming assets and materially improving key efficiency factors and performance.

	•	Our nuclear power plants are located in robust power markets. Our Northeast nuclear power plants are located primarily in the New York and New England power markets, and sell power into the West and Hudson Valley regions of the NYISO and the Massachusetts and Vermont regions of the ISO-NE. These regions had among the highest average power prices in the United States during 2007. We believe that the New York and New England power markets are experiencing a combination of a supply/demand imbalance, high natural gas prices and robust capacity markets, which are factors that we believe will benefit us.

	•	We believe we are well positioned to benefit from carbon dioxide regulation. The core generating functions of our nuclear-fueled power plants do not emit carbon dioxide. By contrast, we expect other non-nuclear power plants that typically set the price of power in the markets in which we operate will be required to incur costs to comply with expected carbon dioxide regulation because those power plants emit carbon dioxide. Because those increased costs are expected to result in higher power prices in our markets, we expect to generate increased net revenue as a result.

	•	We expect to generate additional cash flow growth as long-term contracts with below-market prices expire and power is sold at higher market prices or we renegotiate contracts at higher prevailing market rates. The majority of the existing long-term contracts on our five Northeast power plants expire by the end of 2012. Most of those existing contracts have contract prices that are lower than currently prevailing market prices. As our existing contracts expire, we expect to benefit from the expected increase in power prices in the New York and New England markets.

	•	Relative to generators that utilize fossil fuels, an environment of potentially rising fuel cost is expected to have a smaller adverse effect on our net revenue. Because our fuel costs as a percentage of our total revenues are much less compared to generators who utilize fossil fuels, a rising fuel cost environment will have a smaller effect on our net revenue (operating revenues less fuel and fuel-related expenses).

	•	We expect EquaGen to provide us with operational diversity and growth opportunities. We have a strong track record as a nuclear operating company and believe we will be a leader in every aspect of the nuclear life cycle, including operations, license renewal, decommissioning estimates and acquisitions. In addition to operating our nuclear power plants, we also expect to offer nuclear services, including decommissioning, plant relicensing and plant operations, to third parties. As a diversified and experienced nuclear operator, we expect to be well positioned to grow our operating business by being able to offer sophisticated nuclear operating expertise, as well as ancillary nuclear services, to third parties.

	•	We have a strong and experienced management team. We will be led by a strong management team consisting of leaders in the power industry with extensive nuclear industry expertise and established track records of success.

	•	We do not expect a need to add funds to the decommissioning trusts for our plants to meet current NRC requirements. We believe that the decommissioning funds for our nuclear generating stations


		and the expected earnings on those funds are sufficient to meet current NRC requirements. Consequently, we do not expect a need in the future to contribute additional funds to the decommissioning trusts associated with our plants.

Our Strategy

Our strategy is guided by a set of core values that informs all of our decisions.


	•	We are committed to safe, secure, reliable nuclear operations. Providing safe, secure, reliable nuclear power is our top priority. Our highly skilled work force has a proven track record of safely operating nuclear power plants.

	•	Our primary focus will be on nuclear power. We believe that nuclear power is an important part of solving the problems of global climate change and energy independence. To that end, we will look for ways to make disciplined strategic investments in nuclear power in the future.

	•	Our decision-making process will be guided by our point of view. Power and commodity markets are key drivers of our business. Due to the dynamic nature of these markets, our decision-making process will be guided by our short- and long-term view on the direction of power and commodity markets. We believe that this point of view approach to decision-making will provide us with the flexibility to capitalize on opportunities in an evolving marketplace and will guide a wide range of strategic decisions in a fluid, real-time manner, including:


	•	Hedging contracts. We do not have a pre-determined target hedge level for our nuclear generation portfolio. The size and duration of our power hedging contracts, especially as our existing hedging contracts begin to expire, will, to a large extent, be determined by our point of view on future market power prices and how they compare to the price and terms offered by hedge counterparties at a particular time.

	•	Capital investment. We remain open to pursuing diversity in our asset base. Our point of view on power and commodity markets at a particular time will help us evaluate the economic suitability of specific fuels, technologies, geographic regions and dispatch types. We expect that every opportunity, including greenfield development and asset acquisitions, will be evaluated utilizing this point of view approach to decision-making.


	•	We believe that a creative and skilled work force is a critical element of our performance. We seek to attract, train and retain best-in-class leaders in the power industry who are creative and dedicated to our core values.

	•	We are committed to operating our company in a financially responsible manner. We aim to maintain sufficient financial liquidity and an appropriate capital structure and credit rating to support safe, secure and reliable operations even in volatile market environments. We expect to return cash flows that are greater than needed for investment to shareholders in a timely manner. We anticipate that our primary manner of returning capital to shareholders will be through share repurchase programs.

	•	We are committed to operating our company in a socially responsible manner. We are dedicated members of the communities in which we live and have a history of giving back to those communities. We are dedicated to considering environmental effects in all of our investment decisions and continuing our strong tradition of community involvement.

Summary of Risk Factors

An investment in our common stock involves risks associated with our business, regulatory and legal matters. The following list of risk factors is not exhaustive. Please read carefully the risks relating to these and

other matters described under “Risk Factors” beginning on page 21 and “Forward-Looking Statements” beginning on page 37.

Risks Relating to our Business


	•	Ownership and operation of nuclear power plants create business, regulatory, financial and waste disposal risks that may have a material adverse effect on our business.

	•	The nuclear power plants we own will be exposed to price risk to the extent they must compete for the sale of energy and capacity, and this may harm our profitability.

	•	We face exposure to changes in commodity prices, which can affect the value of assets and operating costs and which may not be adequately hedged against adverse changes.

	•	We are dependent on EquaGen for the operation of our nuclear power plants. We will not be able to easily replace this service provider, or the expertise of its employees, for the operation of our nuclear power plants, and, if our long-term operating contracts are breached or otherwise terminated, we may be materially adversely affected.

	•	New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operations at our nuclear power plants.

	•	We may incur substantial costs to fulfill obligations related to environmental and other matters.

Risks Relating to the Separation


	•	We may be unable to achieve some or all of the benefits that we expect to achieve from our separation from Entergy.

	•	We are being separated from Entergy, our parent company, and, therefore, we have no operating history as a separate, publicly-traded company.

	•	We may be unable to make, on a timely basis, the changes necessary to operate as a separate, publicly-traded company, and we may experience increased costs after the separation or as a result of the separation.

	•	Our agreements with Entergy or EquaGen and their other businesses may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties.

	•	We will be responsible for certain contingent and other corporate liabilities related to the existing non-utility nuclear business of Entergy.

	•	Following the spin-off, we will have substantial indebtedness, which could negatively affect our financing options and liquidity position.

Risks Relating to our Common Stock


	•	There is no existing market for our common stock, and a trading market that will provide you with adequate liquidity may not develop for our common stock. In addition, once our common stock begins trading, the market price of our shares may fluctuate widely.

	•	Substantial sales of common stock may occur in connection with this distribution, which could cause our stock price to decline.

	•	Provisions in our certificate of incorporation, our by-laws, Delaware law and certain agreements we will enter into as part of the separation may prevent or delay an acquisition of our company, which could decrease the trading price of our common stock.

The Separation

On November 3, 2007, the board of directors of Entergy unanimously authorized management of Entergy to pursue a plan to separate its non-utility nuclear business from the rest of Entergy, which we refer to as “the separation” in this information statement. The separation will occur through a distribution to Entergy’s shareholders of all of the shares of common stock of Enexus Energy, which will hold the assets and liabilities of the non-utility nuclear business of Entergy. Following the distribution, Entergy shareholders will own 100% of the shares of our common stock. Immediately prior to the separation, we will also enter into a nuclear services joint venture with Entergy, with equal percentage ownership.

The Entergy board of directors believes that the separation will increase the value of Entergy’s non-utility nuclear business in both the short- and long-term, which value the Entergy board of directors does not believe has been fully recognized by the investment community. Entergy believes that the separation of the non-utility nuclear business will improve both companies’ strategic, operational and financial flexibility. Although there can be no assurance, Entergy believes that, over time, the common stock of both Entergy and our company should have a greater aggregate market value, assuming the same market conditions, than Entergy has in its current configuration.

Before our separation from Entergy, we will enter into the Separation and Distribution Agreement, the Joint Venture Agreements and several other agreements with Entergy or EquaGen to effect the separation and provide a framework for our relationships with Entergy, Entergy’s other businesses and EquaGen after the separation. These agreements will govern the relationships among us, EquaGen, Entergy and Entergy’s other businesses subsequent to the completion of the separation and provide for the allocation among us, EquaGen, Entergy and Entergy’s other businesses, of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the non-utility nuclear business attributable to periods prior to, at and after our separation from Entergy. For more information on the Separation and Distribution Agreement and related agreements, see the section entitled “Certain Relationships and Related Party Transactions.”

We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business. Entergy has informed us that it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any proceeds from the portion of our debt securities that are transferred to Entergy. The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement. Additionally, we intend to enter into one or more credit facilities or other financing arrangements meant to support our working capital and general corporate needs and collateral obligations arising from hedging and normal course of business requirements. For more information on our planned financing arrangements, please see the sections entitled “Unaudited Pro Forma Financial Information of Enexus Energy,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and “Description of Material Indebtedness.”

EquaGen

In connection with the separation, Entergy Nuclear, Inc., currently a wholly-owned subsidiary of Entergy, will become a limited liability company and change its name to EquaGen LLC. We and Entergy will each own a 50% interest in EquaGen immediately prior to completion of the distribution of our common stock. EquaGen is expected to operate the nuclear assets owned by us, and to provide certain services to the regulated nuclear utility operations of Entergy and to third parties. EquaGen will allow certain nuclear operations expertise currently in place at each of Entergy’s nuclear power plants to be accessible by both us and Entergy after the separation.

Upon completion of the transactions contemplated by the Joint Venture Agreements, EquaGen will own:


	•	Entergy Nuclear Operations, currently a wholly-owned subsidiary of Entergy and the current NRC-licensed operator of our nuclear power plants. Entergy Nuclear Operations will remain the operator of our nuclear power plants after the separation and is expected to change its name to EquaGen Nuclear LLC; and

	•	TLG Services, Inc., currently a wholly-owned subsidiary of Entergy that provides decommissioning and other consulting services to Entergy and to other companies in the nuclear industry. TLG Services, Inc. is expected to change its name to TLG Services, LLC.

The Internal Reorganization Prior to the Distribution

To accomplish the separation and related transactions, on the terms and subject to the conditions of the Separation and Distribution Agreement, the Joint Venture Agreements and the other agreements we will enter into, we and Entergy will engage in a number of transactions, including:


	•	Internal business transfers. Entergy will reorganize its corporate structure by means of transfers of equity interests of certain of its subsidiaries so that we hold all of the assets of the non-utility nuclear business and certain assets in the non-utility nuclear services business, and EquaGen holds primarily the non-utility nuclear services business.

	•	EquaGen. We and Entergy will each own a 50% membership interest in EquaGen.

	•	Debt financing. We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities and enter into one or more credit facilities or other financing arrangements.

	•	Repayment of intercompany debt, transfer to Entergy. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business.

Reasons for the Separation

The Entergy board of directors regularly reviews Entergy’s various businesses to ensure that Entergy’s resources are being put to use in a manner that is in the best interests of Entergy and its shareholders. Entergy believes that the separation of the non-utility nuclear business is the best way to unlock the full value of Entergy’s businesses in both the short- and long-term and provides each of Entergy and us with certain opportunities and benefits that would not otherwise be available to Entergy and us. The following are the factors that the Entergy board of directors considered in approving the separation:


	•	Enables equity investors to invest directly in our business;

	•	Optimizes capital structure;

	•	Isolates the commodity and other risks of the non-utility nuclear business from the regulated utility business;

	•	Creates more effective management incentives; and

	•	Allows us and Entergy to focus on opportunities for each company, including M&A opportunities.

Neither we nor Entergy can assure you that, following the separation, any of these benefits will be realized to the extent anticipated or at all. For more information regarding the reasons for the separation, please see “The Separation—Reasons for the Separation.”

Questions and Answers about Enexus Energy and the Separation


*Why am I receiving this document?*		Entergy is delivering this document to you because Entergy’s records show that you were a holder of Entergy common stock on the record date for the distribution of our shares of common stock. As such, you are entitled to receive share(s) of our common stock for each share of Entergy common stock that you held on the record date at p.m. Eastern Time. No action is required for you to participate in the distribution. The distribution will take place on , 2008.

*How will the separation of Enexus Energy work?*		The separation will be accomplished through a series of transactions in which the equity interests of the entities that hold all of the assets and liabilities of Entergy’s non-utility nuclear business will be transferred to us and our common stock will be distributed by Entergy to its shareholders on a pro rata basis as a dividend.

		In addition, immediately prior to the separation, we will enter into a joint venture with equal ownership, referred to as EquaGen, with Entergy. EquaGen will operate and provide services to our six operating nuclear power plants, and also is anticipated to provide certain services to Entergy’s regulated nuclear utility operations.

*Why is the separation of Enexus Energy structured as a distribution?*		Entergy believes that a tax-free distribution of shares of our common stock to the Entergy shareholders is a tax-efficient way to separate its non-utility nuclear business from the rest of its business in a manner that will create long-term value for Entergy shareholders.

*When will the distribution occur?*		We expect that Entergy will distribute our shares of common stock on , 2008 to holders of record of Entergy common stock on , 2008, the record date.

*What do shareholders need to do to participate in the distribution?*		Nothing, but we urge you to read this entire information statement carefully. Shareholders who hold Entergy common stock as of the record date will not be required to take any action to receive our common stock in the distribution. No shareholder approval of the distribution is required or sought. We are not asking you for a proxy, and you are requested not to send us a proxy. You will not be required to make any payment or to surrender or exchange your shares of Entergy common stock or take any other action to receive your shares of our common stock.

		If you own Entergy common stock as of the close of business on the record date, Entergy, with the assistance of BNY Mellon Shareowner Services, the distribution agent, will electronically issue shares of our common stock to you or to your brokerage firm on your behalf by way of direct registration in book-entry form. BNY Mellon Shareowner Services will mail you a book-entry account statement that reflects your shares of our common stock, or your bank or brokerage firm will credit your account for the shares.

		Following the distribution, shareholders whose shares are held in book-entry form may request that their shares of our common stock held in book-entry form be transferred to a brokerage or other account at any time, without charge.


*Will I receive physical certificates representing shares of Enexus Energy common stock following the separation?*		No. Following the separation, neither Entergy nor we will be issuing physical certificates representing shares of Enexus Energy common stock. Instead, Entergy, with the assistance of BNY Mellon Shareowner Services, the distribution agent, will electronically issue shares of our common stock to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. BNY Mellon Shareowner Services will mail you a book-entry account statement that reflects your shares of our common stock, or your bank or brokerage firm will credit your account for the shares. A benefit of issuing stock electronically in book-entry form is that there will be none of the physical handling and safekeeping responsibilities that are inherent in owning physical stock certificates.

*What if I hold shares of Entergy common stock in Entergy’s Share Purchase and Dividend Reinvestment Plan?*		If you hold shares of Entergy common stock in Entergy’s share purchase and dividend reinvestment plan, the shares of our common stock you will receive in the distribution will be distributed to your account for Entergy’s share purchase and dividend reinvestment plan. If you do not want to hold our stock in your account for Entergy’s share purchase and dividend reinvestment plan, instructions will be provided to you on how to transfer such shares to a different account.

*Can Entergy decide to cancel the distribution of the common stock even if all the conditions have been met?*		Yes. The distribution is subject to the satisfaction or waiver of certain conditions, including receipt of certain regulatory approvals. See the section entitled “The Separation—Conditions to the Distribution.” Until the distribution date, Entergy has the right to terminate the distribution, even if all of the conditions are satisfied, if at any time Entergy’s board of directors determines that the distribution is not in the best interests of Entergy and its shareholders or that market conditions are such that it is not advisable to separate the non-utility nuclear business from Entergy and its other businesses.

*Does Enexus Energy plan to pay regular dividends?*		No. Currently, we do not anticipate paying a regular dividend. The declaration and payment of dividends by us in the future will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors.

*Will Enexus Energy incur any debt in the separation?*		Yes. We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business. Entergy has informed us that it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any proceeds from the portion of our debt securities that are transferred to Entergy. The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could


		affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement. Additionally, we intend to enter into one or more credit facilities or other financing arrangements meant to support our working capital and general corporate needs and collateral obligations arising from hedging and normal course of business requirements.

*What will the separation cost?*		Entergy expects to incur pre-tax separation costs of approximately $ million, of which approximately $ will be allocated to us. Over the 12 months following our separation, the portion of these pre-tax costs expected to be recorded in our financial statements is approximately $ to $ million.

*What are the U.S. federal income tax consequences of the distribution to Entergy shareholders?*		The distribution is conditioned upon Entergy’s receipt of a private letter ruling from the IRS and the opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, in each case to the effect that the distribution, together with certain related transactions, will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. Assuming the distribution so qualifies, for U.S. federal income tax purposes, no gain or loss will be recognized by you, and no amount will be included in your income, upon the receipt of shares of our common stock pursuant to the distribution. You will generally recognize gain or loss with respect to cash received in lieu of a fractional share of our common stock. Please see the section entitled “The Separation—Material U.S. Federal Income Tax Consequences of the Distribution.”

*What will Enexus Energy’s relationship be with Entergy following the separation?*		Before the separation of Enexus Energy from Entergy, we will enter into the Separation and Distribution Agreement, the Joint Venture Agreements and several other agreements with Entergy or EquaGen to effect the separation and provide a framework for our relationships with Entergy, Entergy’s other businesses, and EquaGen after the separation. These agreements will govern the relationship among us, EquaGen, Entergy, and Entergy’s other businesses subsequent to the completion of the separation, and provide for the allocation among us, EquaGen, Entergy and Entergy’s other businesses, of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the non-utility nuclear business attributable to periods prior to, at and after our separation from Entergy. We cannot assure you that these agreements will be on terms as favorable to us as agreements with unaffiliated third parties might be. For additional information regarding the separation agreements please see the sections entitled “Risk Factors” and “Certain Relationships and Related Party Transactions,” included elsewhere in this information statement.

*What if I want to sell my Entergy common stock or my Enexus Energy common stock?*		You should consult with your financial advisors, such as your stockbroker, bank or tax advisor. Neither Entergy nor Enexus Energy makes any recommendations on the purchase, retention or sale of shares of Entergy common stock or the Enexus Energy common stock to be distributed.

*What is “regular-way” and “ex-distribution” trading?*		Beginning on or shortly before the record date and continuing up to and through the distribution date, we expect that there will be two markets in Entergy common stock: a “regular-way” market and an


		“ex-distribution” market. Shares of Entergy common stock that trade on the “regular-way” market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade on the “ex-distribution” market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. On the first trading day following the distribution date, all shares of Entergy will trade “ex-distribution.”

		If you decide to sell any shares before the distribution, you should make sure your stockbroker, bank or other nominee understands whether you want to sell your Entergy common stock or your entitlement to Enexus Energy common stock or both pursuant to the distribution.

How will I determine the tax basis I will have in the Enexus Energy shares I receive in the distribution?		Shortly after the distribution is completed, Entergy will provide U.S. taxpayers with information to enable them to compute their tax bases in both Entergy and Enexus Energy shares and other information they will need to report their receipt of Enexus Energy common stock on their 2008 federal income tax returns as a tax-free transaction. Generally, your aggregate basis in the stock you hold in Entergy and shares of our stock received in the distribution (including any fractional interests to which you would be entitled) will equal the aggregate basis of Entergy common stock held by you immediately before the distribution, allocated between your Entergy common stock and Enexus Energy common stock you receive in the distribution in proportion to the relative fair market value of each on the date of the distribution.

		You should consult your tax advisor about the particular consequences of the distribution to you, including the application of state, local and foreign tax laws.

*Where will I be able to trade shares of Enexus Energy common stock?*		There is not currently a public market for our common stock. We intend to apply to list our common stock on the New York Stock Exchange under the ticker symbol . We anticipate that trading in shares of our common stock will begin on a “when-issued” basis on or shortly before the record date and will continue up to and through the distribution date and that “regular-way” trading in shares of our common stock will begin on the first trading day following the distribution date. If trading begins on a “when-issued” basis, you may purchase or sell our common stock up to and through the distribution date, but your transaction will not settle until after the distribution date. We cannot predict the trading prices for our common stock before, on or after the distribution date.

*What will happen to the listing of Entergy common stock?*		Nothing. Entergy common stock will continue to be traded on the New York Stock Exchange and the Chicago Stock Exchange under the symbol “ETR” following the distribution.

*Will the number of Entergy shares I own change as a result of the distribution?*		No. The number of shares of Entergy common stock you own will not change as a result of the distribution.

*Will the distribution affect the market price of my Entergy shares?*		Yes. As a result of the distribution, we expect the trading price of shares of Entergy common stock immediately following the distribution to be lower than the trading price immediately prior to the distribution because the trading price will no longer reflect the value of the non-utility nuclear business. We and Entergy anticipate that until


		the market has fully analyzed the value of Entergy without the non-utility nuclear business, the market price of a share of Entergy common stock may fluctuate significantly. In addition, although we have been advised that Entergy believes that, over time following the distribution, the common stock of Entergy and Enexus Energy should have a higher aggregate market value, assuming the same market conditions that exist as of the date of this information statement, than if Entergy were to remain under its current configuration, there can be no assurance of that, and thus the combined trading prices of a share of Entergy common stock and Enexus Energy common stock after the distribution may be equal to, greater than or less than the trading price of a share of Entergy common stock before the distribution.

*Are there risks to owning Enexus Energy common stock?*		Yes. Our business is subject to both general and specific risks relating to our business, our capital structure, the industry in which we operate, our relationships with Entergy and with EquaGen and our status as a separate publicly-traded company. Our business is also subject to risks relating to the separation. These risks are described in the “Risk Factors” section of this information statement beginning on page 21. We encourage you to read that section and the other information in this information statement carefully.

*Where can I obtain more information?*		Before the separation, if you have any questions relating to the separation or Entergy common stock, you should contact:

		Entergy Corporation Investor Relations 639 Loyola Ave New Orleans, LA 70113

		Tel.: 504-576-4000 Toll-free: 1-800-ENTERGY Fax: 504-576-2879 www.entergy.com

		After the separation, to take place on , 2008, if you have any questions relating to the separation or our common stock, you should contact:

		Enexus Energy Corporation Investor Relations

		Jackson, MS

		Tel.: Toll-free: Fax: www.enexusenergy.com

Terms of the Separation

The following is a summary of the material terms of the separation, distribution and other related transactions.


Distributing company		Entergy Corporation. After the distribution, Entergy will not own any shares of our common stock.

Distributed company		Enexus Energy, a Delaware corporation and a wholly-owned subsidiary of Entergy that holds or will hold the assets and liabilities of Entergy’s non-utility nuclear business. After the distribution, Enexus Energy will be a separate, publicly-traded company.

Distribution ratio		Each holder of Entergy common stock will receive share(s) of our common stock for each share of Entergy common stock held on the record date, , 2008. Cash will generally be distributed in lieu of fractional shares, as described below.

Distributed securities		All of the shares of Enexus Energy common stock owned by Entergy, which will be 100% of our common stock outstanding immediately prior to the distribution, will be distributed pro rata to Entergy’s shareholders. Based on approximately shares of Entergy common stock outstanding on , 2008 and the distribution ratio of share(s) of Enexus Energy common stock for each share of Entergy common stock, approximately shares of our common stock will be distributed to Entergy shareholders. The number of our shares that Entergy will distribute to its shareholders will be reduced to the extent that cash payments are to be made in lieu of the issuance of fractional shares of our common stock.

Fractional shares		Entergy will not distribute any fractional shares of our common stock to its shareholders. Instead, BNY Mellon Shareowner Services, the distribution agent, will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds of the sales pro rata to each holder of Entergy common stock who otherwise would have been entitled to receive a fractional share in the distribution. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares. The receipt of cash in lieu of fractional shares generally will be taxable to the recipient shareholders as described in the section entitled “The Separation—Material U.S. Federal Income Tax Consequences of the Distribution.”

Record date		The record date for the distribution is the close of business on , 2008.

Distribution date		The distribution will take place on , 2008.

Distribution		On the distribution date, Entergy, with the assistance of BNY Mellon Shareowner Services, the distribution agent, will electronically issue shares of our common stock to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. You will not be required to make any payment, surrender or exchange your shares of Entergy common stock or take any other action to receive your shares of our common stock.


		If you sell shares of Entergy common stock in the “regular-way” market through the distribution date, you will be selling your right to receive shares of Enexus Energy common stock in the distribution.

		Registered shareholders will receive additional information from the distribution agent shortly after the distribution date. Following the distribution, shareholders may request that their shares of Enexus Energy common stock held in book-entry form be transferred to a brokerage or other account at any time, without charge. Beneficial shareholders that hold shares through a brokerage firm will receive additional information from their brokerage firms shortly after the distribution date.

Conditions to the distribution		The distribution of our common stock is subject to the satisfaction or, if permissible under the Separation and Distribution Agreement, waiver by Entergy of the following conditions, among other conditions described in this information statement:

		• the Securities and Exchange Commission, or SEC, shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Securities Exchange Act of 1934, as amended, or the Exchange Act, and no stop order relating to the registration statement shall be in effect;

		• all permits, registrations and consents required under the securities or blue sky laws of states or other political subdivisions of the United States or of other foreign jurisdictions in connection with the distribution shall have been received;

		• all required federal and state regulatory approvals (including approvals by the NRC, FERC, New York State Public Service Commission and Vermont Public Service Board) in connection with the distribution and related transactions (including the internal reorganizations by us and Entergy, the formation of EquaGen and debt financing transactions preceding the distribution) shall have been received;

		• the debt financing transactions shall have been completed;

		• Entergy shall have received a private letter ruling from the IRS substantially to the effect that the distribution, together with certain related transactions, qualifies as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

		• Entergy shall have received a legal opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

		• the listing of our common stock on the New York Stock Exchange shall have been approved, subject to official notice of issuance; and


		• no order, injunction or decree issued by any court of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution or any of the transactions related thereto, including the debt financing, the transfers of assets and liabilities contemplated by the Separation and Distribution Agreement or the formation of EquaGen, shall be in effect.

		The fulfillment of these conditions does not create any obligation on Entergy’s part to effect the distribution, and the Entergy board of directors has reserved the right, in its sole discretion, to amend, modify or abandon the distribution and related transactions at any time prior to the distribution date. Entergy has the right not to complete the distribution if, at any time, the Entergy board of directors determines, in its sole discretion, that the distribution is not in the best interests of Entergy or its shareholders or that market conditions are such that it is not advisable to separate the non-utility nuclear business from Entergy.

Stock exchange listing		We intend to file an application to list our shares of common stock on the New York Stock Exchange under the ticker symbol . We anticipate that, on or prior to the record date for the distribution, trading of shares of our common stock will begin on a “when-issued” basis and will continue up to and through the distribution date. For additional information, see the section entitled “The Separation—Trading after the Record Date and before the Distribution Date.”

Transfer agent		BNY Mellon Shareowner Services

		Tel.:

Enexus Energy debt		We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business. Entergy has informed us that it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any proceeds from the portion of our debt securities that are transferred to Entergy. The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement. Additionally, we intend to enter into one or more credit facilities or other financing arrangements meant to support our working capital and general corporate needs and collateral obligations arising from hedging and normal course of business requirements.

		For more information on our planned financing arrangements, please see the sections entitled “Unaudited Pro Forma Financial Information of Enexus Energy,” “Management’s Discussion and Analysis of


		Results of Operations and Financial Condition” and “Description of Material Indebtedness.”

Risks relating to ownership of our common stock and the distribution		Our business is subject to both general and specific risks relating to our business, our capital structure, the industry in which we operate, our relationships with Entergy and EquaGen and our status as a separate, publicly-traded company. Our business is also subject to risks relating to the separation. You should read carefully the section entitled “Risk Factors” beginning on page 21 in this information statement, as well as the other information contained in this information statement.

Tax consequences		Assuming the distribution, together with certain related transactions, qualifies as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, no gain or loss will be recognized by a shareholder, and no amount will be included in the income of a shareholder, upon the receipt of shares of our common stock pursuant to the distribution. However, a shareholder will generally recognize gain or loss with respect to any cash received in lieu of a fractional share of our common stock as described in the section entitled “The Separation—Material U.S. Federal Income Tax Consequences of the Distribution.”

Certain agreements with Entergy		Before our separation from Entergy, we will enter into the Separation and Distribution Agreement, the Joint Venture Agreements and several other agreements with Entergy or EquaGen to effect the separation and distribution and provide a framework for our relationship with Entergy, Entergy’s other businesses and EquaGen after the separation. These agreements will govern the relationship among us, EquaGen, Entergy, and Entergy’s other businesses subsequent to the completion of the separation and provide for the allocation among us, EquaGen, Entergy, and Entergy’s other businesses of assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the non-utility nuclear business attributable to periods prior to, at and after our separation from Entergy. We cannot assure you that these agreements will be on terms as favorable to us as agreements with unaffiliated third parties might be. For a discussion of these arrangements, see the sections entitled “Risk Factors” and “Certain Relationships and Related Party Transactions.”

Summary Historical and Unaudited Pro Forma Combined Financial Data

The following table presents summary historical and pro forma financial data, as well as other data. The income statement data and cash flow statement data for each of the years in the three years ended December 31, 2007 and the balance sheet data as of December 31, 2007 and December 31, 2006 have been derived from our audited Combined Financial Statements included elsewhere in this information statement. The historical financial data should be read in conjunction with our historical financial statements and “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and “Unaudited Pro Forma Financial Information of Enexus Energy” included elsewhere in this information statement.

The unaudited pro forma financial data have been derived from our historical financial statements and adjusted to give effect to the separation and the related transactions. These adjustments are described under “Unaudited Pro Forma Financial Information of Enexus Energy.” Our historical and unaudited pro forma financial data are not necessarily indicative of our future performance or of what our financial position and results of operations would have been if we had operated as a separate, stand-alone entity during the periods shown.


	As of and for the Year Ended
	December 31,
	Pro Forma			Historical
	2007			2007		2006		2005
	(in thousands, except for operating statistics)

Income Statement Data:


Operating Revenues		$2,029,666			$2,029,666		$1,544,873		$1,421,547
Fuel and fuel-related expenses		168,860			168,860		141,026		132,796
Other operation and maintenance expenses		784,383			784,383		651,950		613,468
Other operating expenses		184,435			184,435		153,742		142,485
Depreciation and amortization		99,265			99,265		71,755		58,540
Decommissioning expense		78,607			78,607		35,537		33,202
Operating Income		714,116			714,116		490,863		441,056
Interest expense		417,634			118,172		108,488		90,706
Other income		73,127			102,127		82,734		65,336
Income Before Income Taxes		369,609			698,071		465,109		415,686
Income taxes		97,813			212,023		188,318		160,328
Net Income		271,796			486,048		276,791		255,358

Balance Sheet Data:


Cash and cash equivalents		$795,260			$428,859		$383,809
Property, plant and equipment, net		3,362,998			3,362,998		2,250,817
Total assets		7,439,000			7,018,119		5,352,054
Loans payable - associated companies		-			1,256,627		868,815
Long-term debt, including current maturities		4,738,788			238,788		325,794
Shareholders’ equity		(669,124	)		2,302,583		1,939,828

As of December 31, 2007, we had, on a pro forma basis, negative shareholders’ equity of $669 million as a result of the separation transactions, primarily because we expect to receive net assets with a book value of $2.3 billion and plan to issue and transfer to Entergy $3.0 billion of debt securities.


	As of and for the Year Ended
	December 31,
	Pro Forma	Historical
	2007	2007			2006			2005
	(in thousands, except for operating statistics)

Cash Flow Statement Data:


Cash flows from operating activities			$837,784			$807,629			$560,702
Cash flows from investing activities			(883,396	)		(450,219	)		(368,496	)
Cash flows from financing activities			90,662			(185,942	)		(119,932	)
Other Cash Flow Data:
Construction/capital expenditures			($259,977	)		($302,865	)		($161,149	)
Nuclear fuel purchases			(225,684	)		(100,015	)		(164,564	)

Operating Statistics:


Net MW in operation at December 31			4,998			4,200			4,105
Average price realized per MWh			$52.69			$44.33			$42.26
GWh billed			37,570			34,847			33,641
Capacity factor			89%			95%			93%
Refueling outage days			123			58			71


	As of and for the Year Ended December 31,
	Pro Forma			Historical
	2007			2007			2006			2005
	(in thousands)
EBITDA


Net Income	$	271,796		$	486,048		$	276,791		$	255,358
add back: Income taxes		97,813			212,023			188,318			160,328
subtract: Other income		73,127			102,127			82,734			65,336
add back: Interest expenses		417,634			118,172			108,488			90,706

Operating Income		714,116			714,116			490,863			441,056

add back: Depreciation and amortization		99,265			99,265			71,755			58,540
add back: Miscellaneous other income		(29,715	)		(715	)		(427	)		(1,504	)

EBITDA	$	783,666		$	812,666		$	562,191		$	498,092

EBITDA, which we define as earnings before interest, taxes, depreciation and amortization and interest and dividend income, is a non-GAAP financial measure. There are material limitations to using a measure such as EBITDA, including the difficulty associated with comparing results among more than one company and the inability to analyze certain significant items, including depreciation and interest expense, that directly affect our net income or loss. EBITDA should be considered in addition to, but not as a substitute for, other measures of financial performance prepared in accordance with GAAP. We consider EBITDA to be important because it provides our board of directors, management and investors with an understanding of our financial performance and our ability to make capital expenditures.

We understand that, although EBITDA is frequently used by securities analysts, lenders and others in their evaluation of companies, EBITDA has limitations as an analytical tool, and you should not consider it in

RISK FACTORS

You should carefully consider each of the following risk factors and all of the other information set forth in this information statement. The risk factors generally have been separated into three groups: (i) risks relating to our business, (ii) risks relating to the separation, and (iii) risks relating to ownership of our common stock. Based on the information currently known to us, we believe that the following information identifies the material risk factors affecting our company in each of these categories of risks. However, the risks and uncertainties our company faces are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business, financial condition or results of operations. In addition, past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods.

Risks Relating to our Business

Ownership and operation of nuclear power plants create business, regulatory, financial and waste disposal risks that may have a material adverse effect on our business.

We and our subsidiaries are subject to the risks arising from owning and operating nuclear power plants. These include:


	•	Capacity factors. Capacity factors, defined as actual plant output divided by maximum potential plant output for the period, significantly affect our results of operations. Nuclear plant operations involve substantial fixed operating costs, as well as non-fixed costs associated with plant operating conditions and issues. Consequently, to be successful, we must consistently operate our nuclear power plants at high capacity factors. Lower capacity factors negatively affect our margins by requiring us to spread the fixed costs over fewer units of production and to purchase additional energy in the spot or forward markets in order to satisfy our supply needs. For sales of power on a unit-contingent basis coupled with a guarantee of availability, power is supplied from a specific generation asset; if the asset is unavailable, we are not liable to the purchaser for any damages, unless the actual availability over a specified period of time is below an availability threshold specified in the contract. In the event our plants were operating below these guaranteed availability thresholds, we would be subject to price risk for the undelivered power. Additionally, as of March 31, 2008, 5% of our planned generation for 2008 was sold forward on a firm liquidated damages basis. Under a firm liquidated damages contract, the transaction requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset); if we fail to deliver energy, we must compensate the other party as specified in the contract.

	•	Refueling and other outages. Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and historically average approximately 30 days in duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs increase. As a result, we may face lower margins due to higher costs and lower energy sales for unit-contingent contracts or potentially higher energy replacement costs for firm liquidated damages contracts and for unit-contingent contracts with capacity guarantees that are not met due to extended or unplanned outages.

	•	Cost and supply of nuclear fuel. Our nuclear power plants rely on a limited number of suppliers to provide uranium fuel (and its conversion, enrichment and fabrication) required for the operation of the plant. It will be necessary for us to enter into additional arrangements to acquire nuclear fuel and related services in the future. Uranium market supply became extremely limited in 2006 and 2007 and market prices have been highly volatile during this period. Market prices for uranium concentrates have risen from about $7 per pound in December 2000 to a 2007 range of $70 to $135 per pound. The costs of obtaining supplies have therefore increased greatly for nuclear fuel users. Our financial performance is dependent on the continued performance by suppliers of their


		obligations under their long-term agreements. Our financial results could be materially adversely affected if any one supplier fails to fulfill its contractual obligations and we are unable to find other suppliers that can perform under terms that allow us to achieve the same level of profitability. As a result of the failure of a major supplier to meet its contractual obligations, we may face higher costs to secure other suppliers, which may result in potential disruptions to our business and have a material adverse effect on our results of operations, financial condition and liquidity.


	•	Nuclear regulatory risk. Under the Atomic Energy Act and Energy Reorganization Act, the NRC heavily regulates nuclear power plants. The NRC may modify, suspend or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially adversely affect our results of operations, financial condition and liquidity. Events at nuclear power plants owned by others, as well as those owned by us, may cause the NRC to initiate such actions. As a result, if an incident did occur at any nuclear generating unit—whether owned by us or not—it could materially adversely affect our results of operations, financial condition and liquidity.

	•	Operational risk. All six of our operating nuclear power plants began commercial operations in the 1970s. Older equipment may require significant capital expenditures to keep each of our nuclear power plants operating efficiently. This equipment is also likely to require periodic upgrading and improvement. Operations at any of the nuclear generating units owned by us could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. This could result in lost revenue, increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under our contracts with customers.

	•	Spent nuclear fuel storage. We regularly incur costs for the on-site storage of spent nuclear fuel. The approval of a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, and the timing of such facility opening, may affect the costs associated with storage of spent nuclear fuel. In addition, the availability of a repository for spent nuclear fuel may affect the ability to fully decommission the nuclear units.

	•	Nuclear accident risk. Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include personal injury, loss of life and property damage. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $100.6 million per reactor. With 104 reactors currently operating in the United States, this translates to a total public liability cap of approximately $10.4 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, we carry the maximum available amount of primary nuclear liability insurance with American Nuclear Insurers (currently $300 million for each operating site). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the $300 million in primary liability insurance coverage, each owner of a nuclear plant reactor will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the $300 million primary level, up to a maximum of $100.6 million per reactor per incident. The retrospective premium payment is currently limited to $15 million per year per reactor until the aggregate public liability for each licensee is paid up to the $100.6 million cap. Nuclear accident damage to on-site facilities is covered by Nuclear Electric Insurance Limited up to the limits of the primary and excess property policies in force at the time of the accident. We maintain property insurance for our nuclear units in


		excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. For additional details, see “Employees, Properties and Facilities, Government Regulation and Legal Proceedings—Regulations Generally Applicable to Our Business—Price-Anderson Act.”


	•	Decommissioning. Owners of nuclear generating plants have an obligation to decommission those plants. We maintain decommissioning trust funds for this purpose. In connection with the acquisition of certain of our nuclear power plants, we or our predecessor also acquired decommissioning trust funds that are funded in accordance with NRC regulations. An early plant shutdown, poor investment results or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that we may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

The nuclear power plants we own will be exposed to price risk to the extent they must compete for the sale of energy and capacity, and this may harm our profitability.

We are not guaranteed any rate of return on our capital investments in our business. In particular, the sale of capacity and energy from our nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. On a blended basis, as of December 31, 2007, we have sold forward 89%, 78% and 51% of our generation portfolio’s planned energy output and installed capacity for 2008, 2009 and 2010, respectively. The obligations under most of these agreements are contingent on a unit being available to generate power. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event we fail to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. In addition, for those obligations that are not unit-contingent, we will be required to pay the purchaser the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.

Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times market prices may experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time, there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address price volatility and other issues in these markets.

Among the factors that could affect market prices for electricity and fuel, all of which are beyond our control to a significant degree, are:


	•	prevailing market prices for natural gas, uranium (and its conversion, enrichment and fabrication), coal, oil and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;

	•	seasonality;

	•	availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;

	•	changes in production and storage levels of natural gas, lignite, coal and crude oil and refined products;

	•	liquidity in the general wholesale electricity market;

	•	the actions of external parties, such as the FERC and local independent system operators, as well as other state and Federal energy regulatory policies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;

	•	transmission or transportation constraints, inoperability or inefficiencies;

	•	the general demand for electricity;


	•	weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;

	•	the rate of growth in demand for electricity as a result of population changes, regional economic conditions and the implementation of conservation programs;

	•	regulatory policies of state agencies that affect the willingness of our customers to enter into long-term contracts generally, and contracts for energy in particular;

	•	increases in supplies due to actions of our current competitors or new market entrants, including the development of new generation facilities, expansion of existing generating facilities, the disaggregation of vertically integrated utilities and improvements in transmission that allow additional supply to reach our markets;

	•	union and labor relations;

	•	changes in federal and state energy and environmental laws and regulations, including but not limited to the effect that proposed emission controls such as the Regional Greenhouse Gas Initiative might have on prices; and

	•	natural disasters, wars, embargoes, terrorist actions and other catastrophic events.

We face exposure to changes in commodity prices, which can affect the value of assets and operating costs and which may not be adequately hedged against adverse changes.

To manage our near-term financial exposure related to commodity price fluctuations, we enter into contracts to hedge portions of our purchase and sale commitments and our requirements for uranium (and its conversion, enrichment and fabrication) within established risk management guidelines. As part of this strategy, we utilize fixed-price forward physical purchase and sales contracts. The coverage may vary over time, and we may also elect to not hedge certain volumes during certain years. To the extent we do not have hedged positions, fluctuating commodity prices can materially adversely affect our results of operations, financial condition and liquidity.

Although we devote a considerable amount of management time and effort to these risk management strategies, we cannot eliminate all the risks associated with these activities. As a result of these and other factors, we cannot predict with precision the effects that risk management decisions may have on our results of operations, financial condition and liquidity.

Currently, some of the agreements to sell the power produced by our nuclear power plants contain provisions that require an Entergy subsidiary to provide collateral to secure our obligations under the agreements. The Entergy subsidiary generally would be required to provide collateral either based upon the difference between the current market and contracted power prices in the regions where we sell power or based on an independent fixed dollar amount. The primary form of collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. As of December 31, 2007, based on power prices at that time, Entergy had in place as collateral $702 million of Entergy Corporation guarantees for wholesale transactions, including $63 million of guarantees that support letters of credit. The assurance requirement is estimated to increase by an amount up to $294 million if gas prices increase $1 per MMBtu in both the short- and long-term markets.

In connection with the separation, we expect to replace these Entergy corporation guarantees related to power sale collateral requirements with a combination of letters of credit, cash, guarantees issued by us or liens on our property. Reductions in our credit quality or changes in the market prices of energy commodities could change the form of collateral or increase the cash collateral required to be posted in connection with hedging and risk management activities, which could materially adversely affect our results of operations, financial condition and liquidity.

Our hedging and risk management activities are exposed to the risk that counterparties that owe us money, energy or other commodities will not fulfill their obligations to us. If the counterparties to these

arrangements fail to perform, we might be forced to acquire alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we might incur losses in addition to amounts, if any, already paid to the counterparties.

We are dependent on EquaGen for the operation of our nuclear power plants. We will not be able to easily replace this service provider, or the expertise of its employees, for the operation of our nuclear power plants, and, if our long-term operating contracts are breached or otherwise terminated, we may be materially adversely affected.

Immediately prior to the separation, we will form a joint venture with equal ownership with Entergy called EquaGen. The Joint Venture Agreements set out the terms governing the formation and management of EquaGen. EquaGen is expected to operate and maintain our nuclear power plants.

The terms governing the operation and maintenance of each of our nuclear power plants are set forth in the Operating Agreements. Under the Operating Agreements, Entergy Nuclear Operations will be responsible for operating and making capital improvements to each of our nuclear power plants and maintaining permits and approvals in accordance with good utility practice, applicable laws and regulations, the applicable NRC Operating License and the budgets approved by us for each of our six operating nuclear power plants. Entergy Nuclear Operations will operate as an NRC-licensed entity, and any new operator would have to be approved by the NRC prior to replacement. We will be dependent on Entergy Nuclear Operations for the operation of our plants, and we will not be able to easily replace Entergy Nuclear Operations for the operation of our plants without additional expense. If the Operating Agreements are breached or otherwise terminated, we may be materially adversely affected. For example, the Operating Agreements and the Joint Venture Agreements provide that if EquaGen is operating four or fewer of our nuclear power plants, then the Operating Agreements for the remaining nuclear power plants will be terminated if the Board of EquaGen has not exercised its right to override the automatic termination. If the Board of EquaGen decided to not override automatic termination of the Operating Agreements, we may (if Entergy elects to exercise its rights under the Joint Venture Agreements) be obligated to either purchase the subsidiaries of EquaGen that carry on its “third party” business, or purchase Entergy’s 50% membership interest in EquaGen. We may not have sufficient cash to fulfill these obligations, if they are triggered, or we may experience pressure on our liquidity as a result of the obligation to purchase either the subsidiaries of EquaGen or Entergy’s 50% membership interest in EquaGen.

EquaGen will also enter into Shared Services Agreements with subsidiaries of Entergy. Under these agreements, EquaGen will obtain certain management and technical services that it in turn provides to us through the Operating Agreements with Entergy Nuclear Operations.

New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operations at our nuclear power plants.

New and existing concerns have been expressed in public forums about the safety of nuclear power plants and nuclear fuel, in particular in the Northeast United States, which is where five of our six nuclear power plants are located. These concerns have led to, and are expected to continue to lead to, various proposals to federal regulators as well as some state and local governing bodies in some localities where we own nuclear power plants for legislative and regulatory changes that could lead to the shut-down of nuclear units, denial of license extension applications, municipalization of nuclear power plants, restrictions on nuclear power plants as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning and operating nuclear power plants. If any of the existing proposals, or any proposals that may arise in the future, relating to legislative and regulatory changes becomes effective, it could have a material adverse effect on our results of operations, financial condition and liquidity.

We may incur substantial costs to fulfill obligations related to environmental and other matters.

Our business is subject to extensive environmental regulation by local, state and federal authorities. These laws and regulations affect the manner in which we conduct our operations and make capital expenditures. These laws and regulations also affect how we manage air emissions, discharges to water, solid

and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, hazardous materials transportation and similar matters. Federal, state and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel and operation and maintenance expenditures. Violations of these requirements can subject us to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up, civil penalties, criminal prosecution and exposure to third-parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, we are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by us and of property contaminated by hazardous substances we generate.

For example, we will face increased costs as a result of joining a groundwater monitoring initiative program after the detection of radioactive material, primarily tritium, in groundwater at several plants in the United States, including our Indian Point Energy Center. In addition to tritium, other radionuclides, such as strontium, have been detected in on-site groundwater at Indian Point Energy Center. Lower levels of tritium have also been found at the Pilgrim and Palisades plants, and those sites are currently in the investigatory phase to address these findings. In cooperation with regulators and interested parties, we have completed a comprehensive site characterization and groundwater investigation at Indian Point Energy Center. Remedial actions are underway and we expect them to be completed in 2008. In October 2007, the EPA announced that it was consulting with the NRC and the New York State Department of Environmental Conservation regarding Indian Point Energy Center. The EPA stated that after reviewing data it confirmed with the New York State Department of Environmental Conservation that there have been no violations of federal standards for radionuclides in drinking water supplies.

As another example, in November 2003, the New York State Department of Environmental Conservation issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental impacts attributable to the intake of cooling water at Indian Point 2 and Indian Point 3. The draft permit would require us to take certain steps to assess the feasibility of retrofitting the site to install cooling towers because we have announced our intent to apply for NRC license renewal at Indian Point 2 and Indian Point 3. Upon its becoming effective, the draft permit would also require the facilities to take an annual 42 unit-day outage (coordinated with the existing refueling outage schedule) and provide a payment into a New York State Department of Environmental Conservation account until the start of cooling tower construction. We are participating in the administrative process to request that the draft permit be modified prior to final issuance and we oppose any requirement to install cooling towers or to begin annual outages at Indian Point 2 and Indian Point 3. We notified the New York State Department of Environmental Conservation that the cost of retrofitting Indian Point 2 and Indian Point 3 with cooling towers likely would cost, in 2003 dollars, at least $740 million in capital costs and an additional $630 million in lost generation during construction. Due to fluctuations in power pricing and because a retrofitting of this size and complexity has never been undertaken, significant uncertainties exist in these estimates and, therefore, could be materially higher than estimated.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain, maintain or comply with any such approval, the operation of our facilities could be stopped or become subject to additional costs. For more information, reference is made to “Environmental Matters” and “Employees, Properties and Facilities, Government Regulation and Legal Proceedings—Regulations Generally Applicable to Our Business.”

We rely on power transmission facilities that we do not own or control and are subject to transmission constraints within the New England, New York and Midwest markets. If these facilities fail to provide us with adequate transmission capacity, we may be restricted in our ability to deliver wholesale electric power to our customers and we may either incur additional costs or forgo revenues.

We depend on transmission facilities operated by the Independent System Operator New England, the New York Independent System Operator and the Midwest Independent System Operator in New England, New York and the Midwest, respectively, and on transmission systems owned and operated by others to deliver the wholesale power we sell from our power generation plants to our customers. If transmission is disrupted, if the transmission capacity infrastructure is inadequate or if the rules related to transmission service are materially altered, our ability to sell and deliver wholesale power may be materially adversely affected, causing us to incur additional costs or forego revenues.

Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could materially adversely affect our business.

As power generators, we face heightened risk of an act or threatened act of terrorism, either a direct act against one of our generation facilities or an inability to operate as a result of systemic damage resulting from an act against the transmission and distribution infrastructure that we use to transport our power. In particular, we may experience increased capital and operating costs to implement increased security for our nuclear power plants, such as additional physical facility security and additional security personnel. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could materially adversely affect results of operations, financial condition and liquidity.

Market performance and other changes may decrease the value of EquaGen benefit plan assets, which then could require significant additional funding.

EquaGen will maintain pension and postretirement benefit plans on behalf of certain of its employees. The performance of the capital markets affects the values of the assets held in trust under pension and postretirement benefit plans such as those that will be maintained by EquaGen. A decline in the market value of the assets of those plans may increase the funding requirements relating to the associated benefit plan liabilities. Additionally, changes in interest rates will affect the liabilities under those pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. The funding requirements of the obligations related to those pension and postretirement benefit plans can also increase as a result of changes in retirements, life expectancy assumptions, or federal regulations. These considerations could adversely affect our financial condition because we will be responsible, under the Joint Venture Agreements, the Operating Agreements or otherwise, for the funding obligations under those plans. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Critical Accounting Estimates—Qualified Pension and Other Postretirement Benefits” and Note 7 to the financial statements.

The decommissioning trust fund assets for our nuclear power plants may not be adequate to meet decommissioning obligations if one or more of our nuclear power plants is retired earlier than the anticipated shutdown date, and market performance and other changes may decrease the value of assets in the decommissioning trusts, which then could require significant additional funding.

In connection with the purchase of certain of our nuclear power plants, we received decommissioning trusts to fund our obligation to decommission those plants, whereas for the Indian Point 3 and FitzPatrick plants purchased in 2000, we executed decommissioning agreements with the seller of those plants that specify our decommissioning obligations. Under the decommissioning agreements, the seller of those nuclear power plants retained the decommissioning trusts and the decommissioning liabilities for those nuclear power plants. The performance of the capital markets affects the values of the debt and equity securities held in the decommissioning trusts. We have significant decommissioning obligations and there are significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. A decline in the market value of the assets may increase the funding

requirements of these obligations. Additionally, changes in interest rates affect our decommissioning obligations; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, regulatory changes, including increased decommissioning costs, may also increase the funding requirements of the obligations related to our decommissioning of plants.

In addition, under NRC regulations, we are permitted to project the NRC-required decommissioning amount and the amount in each of our nuclear power plant’s decommissioning trusts. The projections are made based on the scheduled shutdown date and the mid-point of the subsequent decommissioning process for each of our nuclear power plants, with the earliest scheduled shutdown being Vermont Yankee in 2012. As a result, if the projected amount of our decommissioning trusts exceeds the projected NRC-required decommissioning amount, then our decommissioning obligations are considered to be funded in accordance with NRC regulations. With respect to the decommissioning trusts for Vermont Yankee, Indian Point 2 and Palisades, the total amount in each of those trusts as of December 31, 2007 would not have been sufficient to initiate and complete the immediate near-term decommissioning of the respective unit as of such date, but rather the funds would have been sufficient to place the unit in a condition of safe storage or “SAFSTOR” status pending future completion of decommissioning. For example, if we had decided to shutdown and immediately begin decommissioning one of those nuclear power plants on December 31, 2007, our trust funds for the plant would have been insufficient and we would have been required to rely on other capital resources to fund the entire decommissioning obligations unless the completion of decommissioning could be deferred during many years of “SAFSTOR” status. Thus, if we decide to shutdown one of our nuclear power plants earlier than the scheduled shutdown date, we may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations, which would require us to obtain funding from other sources. As a result, under these circumstances, our liquidity and financial condition could be materially adversely affected.

A failure to obtain renewed licenses for the continued operation of our generating units could have a material adverse effect on our operations and lead to an increase in decommissioning costs and depreciation rates.

The operating licenses for Vermont Yankee, Pilgrim, Indian Point 2, FitzPatrick and Indian Point 3 expire in 2012 to 2015. License renewal applications are pending for five of our nuclear power plants, and are the subject of public and local political debate. Various parties, including the New York State Attorney General, have expressed opposition to the pending license renewal applications. If the NRC does not renew the operating licenses for one or more of these plants, our results of operations could be materially adversely affected by loss of revenue associated with the plant or plants, increased depreciation rates and accelerated decommissioning costs.

We depend upon our senior management and the senior management of EquaGen, and our business may be adversely affected if we cannot retain senior management.

Our business is highly regulated and very complex and the operation of our business requires specialized industry, technical and regulatory knowledge. As a result, our success depends upon the retention of our experienced senior management and the senior management of EquaGen with specialized experience with nuclear generation, operation and services. We might not be able to find qualified replacements for the members of our senior management team if their services were no longer available to us; accordingly, the loss of critical members of our senior management team could have a material adverse effect on our ability to effectively implement our business plan.

Our business, financial condition and results of operations could be adversely affected by strikes, work stoppages or a slow down by employees and contractors at EquaGen, and we may face difficulties in competing for qualified workers as our workforce retires.

As of March 31, 2008, approximately 50.7% of the employees at Entergy Nuclear Operations who operate and maintain our nuclear power plants and, at some sites, provide security services to our nuclear power plants, were covered by collective bargaining agreements. In the event that the union employees or contractors strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we could experience reduced power generation or outages if Entergy Nuclear Operations does not

have sufficient personnel to operate or provide security services for the plants. Entergy Nuclear Operations has strike contingency plans to assure safe operation of its plants and compliance with NRC requirements, but whether Entergy Nuclear Operations will have adequate personnel, by direct employment, contract, or otherwise, in such circumstances is uncertain. Strikes, work stoppages or slowdowns, or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our results of operations, financial condition and liquidity.

In addition, a number of our employees at our plants are close to retirement. The market for skilled nuclear power plant employees is very competitive because of the technical skills and knowledge necessary to operate a nuclear power plant. As our workforce retires, we will face increased costs to recruit and retain new employees, and if we are unable to replace our retiring workers, we could experience potential knowledge and expertise gaps.

Maintenance, expansion and refurbishment of our nuclear power plants involve material risks that could result in unplanned power outages or reduced output and could have a material adverse effect on our results of operations, financial condition and liquidity.

Many of our facilities are older and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability. The unexpected requirement of large capital expenditures could have a material adverse effect on our results of operations, financial condition and liquidity. Operations at any of our nuclear power plants could degrade to the point where we have to shutdown the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. We may choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, we may lose revenue and incur increased expense to meet our contractual commitments. Moreover, we are becoming more dependent on fewer suppliers for key parts of our nuclear power plants that may need to be replaced or refurbished. This dependence on a reduced number of suppliers could result in replacement delays in obtaining qualified parts and, therefore, greater expense for us.

Our business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

Our business is subject to extensive federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause us to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.

Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of our nuclear power plants, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy. FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. FERC’s orders that grant our generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that we can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, our market-based sales are subject to certain market behavior rules, and if any of our generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If our generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates we charge for power from our facilities.

We are also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of our generation facilities that sell energy and capacity into the wholesale power markets.

The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism and claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, as well as proposals to re-regulate the markets, impose a generation tax or require divestiture by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to our business planning models. If competitive restructuring of the electric power markets is reversed, discontinued or delayed, our results of operations, financial condition and liquidity could be materially adversely affected.

Risks Relating to the Separation

We may be unable to achieve some or all of the benefits that we expect to achieve from our separation from Entergy.

We may be unable to achieve the full strategic and financial benefits that we expect will result from our separation from Entergy or such benefits may be delayed or may not occur at all. For example, there can be no assurance that analysts and investors will regard our corporate structure as clearer and simpler than the current Entergy corporate structure or place a greater value on our company as a stand-alone company than on our business being a part of Entergy. As a result, in the future, the aggregate market price of Entergy’s common stock and our common stock as separate companies may be less than the market price per share of Entergy’s common stock had the separation and distribution not occurred.

We are being separated from Entergy, our parent company, and, therefore, we have no operating history as a separate, publicly-traded company.

The historical and pro forma financial information included in this information statement does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate, publicly-traded company during the periods presented or those that we will achieve in the future primarily as a result of the following factors:


	•	Prior to our separation, our business was operated by Entergy as part of its broader corporate organization, rather than as a separate, publicly-traded company. Entergy or one of its affiliates performed various corporate functions for us, including, but not limited to, accounts payable, cash management, treasury, tax administration, legal, regulatory, certain governance functions (including compliance with the Sarbanes-Oxley Act of 2002 and internal audit) and external reporting. Our historical and pro forma financial results reflect allocations of corporate expenses from Entergy for these and similar functions. These allocations may be inconsistent with what we have determined the allocations should be had we operated as a separate, publicly-traded company.

	•	Currently, our business is integrated with the other businesses of Entergy. Historically, we have shared economies of scope and scale in costs, employees, vendor relationships and certain customer relationships. While we expect to enter into the Joint Venture Agreements and short-term transition


		agreements that will govern certain commercial and other relationships among us, Entergy, EquaGen and Entergy’s other businesses, those contractual arrangements may not capture the benefits our business has enjoyed as a result of being integrated with Entergy and its other businesses. The loss of these benefits of scope and scale may have an adverse effect on our business, results of operations, financial condition and liquidity following the completion of the separation.


	•	Subsequent to the completion of our separation, the borrowing costs for our business may be higher than Entergy’s borrowing costs and our borrowing costs as reflected in our historical financial statements prior to our separation. Please see the section entitled “Description of Material Indebtedness.”

We may be unable to make, on a timely basis, the changes necessary to operate as a separate, publicly-traded company, and we may experience increased costs after the separation or as a result of the separation.

Following the completion of our separation, Entergy or EquaGen will be contractually obligated to provide to us only those services specified in the agreements we enter into with Entergy or EquaGen in connection with the separation. If any services provided by Entergy are not covered by the various agreements we will enter into with Entergy, we may be unable to replace, on comparable terms, the services that Entergy previously provided to us. Also, upon the expiration or termination of the Joint Venture Agreements, the Operating Agreements, the Shared Services Agreements or other agreements, many of the services that are covered in such agreements will be provided internally or by unaffiliated third parties, and we expect that in some instances we may incur higher costs to obtain such services than we incurred under the terms of such agreements. In addition, if Entergy or EquaGen does not continue to perform effectively the services that are called for under the Joint Venture Agreements, the Operating Agreements, the Shared Services Agreements and the other agreements, we may not be able to operate our business effectively and our profitability may decline. For more information, please see the section entitled “Certain Relationships and Related Party Transactions.”

Our agreements with Entergy or EquaGen and their other businesses may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties.

The agreements we entered into with Entergy or EquaGen, including the Separation and Distribution Agreement, the Joint Venture Agreements and the other agreements, were prepared in the context of our separation from Entergy while we were still part of Entergy and, accordingly, may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties. For more information, please see the section entitled “Certain Relationships and Related Party Transactions.”

We will be responsible for certain contingent and other corporate liabilities related to the existing non-utility nuclear business of Entergy.

Under the Separation and Distribution Agreement, we will assume and be responsible for certain contingent and other corporate liabilities related to the existing non-utility nuclear business of Entergy (including associated costs and expenses, whether arising prior to, at or after the distribution). In addition, under the Tax Sharing Agreement, we will assume and be responsible for certain tax liabilities. We may be required to indemnify Entergy for these liabilities, which may have a material adverse effect on our results of operations, liquidity and financial condition. In addition, we may also be responsible for sharing other liabilities, if any, which do not relate to either our business or the business of Entergy. For a more detailed description of the Separation and Distribution Agreement, the Tax Sharing Agreement and treatment of certain historical Entergy contingent and other corporate liabilities, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Tax Sharing Agreement — Post-Separation,” “Certain Relationships and Related Party Transactions — Agreements with Entergy — Separation and Distribution Agreement and “Certain Relationships and Related Party Transactions — Agreements with Entergy — Tax Sharing Agreement.”

Following the spin-off, we will have substantial indebtedness, which could negatively affect our financing options and liquidity position.

Because of the debt we intend to incur, we expect that, on a pro forma basis as of December 31, 2007, we had approximately $4.7 billion of indebtedness and annual interest expense of approximately $418 million.

The extent to which we are leveraged could:


	•	reduce our credit rating and limit our ability to obtain additional financing in the future for working capital, capital expenditures and acquisitions;

	•	limit our ability to refinance our indebtedness on terms acceptable to us or at all;

	•	require us to dedicate a significant portion of our cash flow from operations to paying the principal of and interest on our indebtedness, thereby reducing funds available for other corporate purposes and also limiting our ability to service our debt in the future;

	•	restrict actions we may take when operating our business, including restrictions on entering into new contracts or requirements to post cash collateral or otherwise support existing hedging or forward sale agreements; and

	•	make us more vulnerable to economic downturns, limit our ability to withstand competitive pressures, and restrict our ability to react to changes in the economy or our industry.

Our financing arrangements will subject us to various restrictions that could limit our operating flexibility.

We expect that our credit facilities and other financing arrangements will contain covenants and other restrictions that, among other things, will require us to satisfy certain financial tests and maintain certain financial ratios and restrict our ability to incur additional indebtedness. In addition, we expect that both our debt securities and the credit facilities might restrict our ability to incur debt, pay dividends and create liens. The restrictions and covenants in our anticipated financing arrangements, and in future financing arrangements, may limit our ability to respond to market conditions, provide for capital investment needs or take advantage of business opportunities by limiting the amount of additional borrowings we may incur. See “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources.”

We may not have access to capital on acceptable terms, and if we are not able to obtain sufficient financing, we may be unable to maintain or grow our business.

Following the separation, our credit ratings are expected to be below investment grade, which is below the current ratings of Entergy. Differences in credit ratings affect the interest rate charged on financings, as well as the amounts of indebtedness and types of financing structures that may be available to us. Regulatory restrictions and the terms of our indebtedness will limit our ability to raise capital through our subsidiaries, pledge the stock of our subsidiaries, encumber the assets of our subsidiaries and cause our subsidiaries to guarantee our indebtedness. We may not be able to raise the capital we require on acceptable terms, if at all. If we are not able to obtain sufficient financing, we may be unable to maintain or grow our business. In addition, our financing costs may be higher than they were as part of Entergy as reflected in our historical financial statements. Further, issuances of equity securities will be subject to limitations imposed on us in the Tax Sharing Agreement.

The ownership by our executive officers and some of our directors of shares of common stock, options or other equity awards of Entergy may create, or may create the appearance of, conflicts of interest.

Because of their current or former positions with Entergy, substantially all of our executive officers, including our chief executive officer, and some of our non-employee director nominees own shares of Entergy common stock, options to purchase shares of Entergy common stock or other equity awards based on Entergy common stock. Upon Entergy’s distribution of all of our outstanding common stock to Entergy shareholders, these options and other equity awards will be converted into options and other equity awards based in part on Entergy common stock and in part on our common stock. Accordingly, following Entergy’s distribution of all

of our outstanding common stock to Entergy shareholders, these officers and non-employee directors will own shares of both Entergy and our common stock and hold options to purchase and other equity awards based on shares of common stock of both Entergy and us. The individual holdings of common stock, options to purchase common stock and other equity awards based on common stock of Entergy may be significant for some of these persons compared to these persons’ total assets. Ownership by our directors and officers, after the separation, of common stock, options to purchase common stock and other equity awards based on common stock of Entergy may create, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for Entergy than the decisions do for us.

If the distribution, together with certain related transactions, were to fail to qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, then our shareholders and/or Entergy could be required to pay U.S. federal income taxes.

Entergy has requested a private letter ruling from the IRS, substantially to the effect that the distribution of our common stock to its shareholders will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. A private letter ruling from the IRS generally is binding on the IRS.

The IRS, however, will not rule on some requirements necessary for tax-free treatment under Section 355 of the Code. Therefore, in addition to obtaining the ruling from the IRS, Entergy has made it a condition to the distribution that Entergy obtain an opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, that the distribution will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The opinion will rely on the ruling as to matters covered by the ruling. In addition, the opinion will be dependent on, among other things, certain assumptions and representations as to factual matters made by Entergy and us. The opinion will not be binding on the IRS or the courts, and the IRS or the courts may not agree with the opinion. For more information regarding the tax opinion and the private letter ruling, please see the section entitled “The Separation—Material U.S. Federal Income Tax Consequences of the Distribution.”

Our company could be materially adversely affected by a potential indemnity liability to Entergy if the distribution is not treated as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. In general, under the terms of the Tax Sharing Agreement we will enter into with Entergy in connection with the separation, if the distribution failed to qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code and such failure was not the result of actions taken after the distribution by Entergy or us, we and Entergy would be responsible for % and %, respectively, of any taxes imposed on Entergy as a consequence. If the failure was the result of actions taken after the distribution by Entergy or us, the party responsible for the failure would be responsible for all taxes imposed on Entergy as a consequence. For a more detailed discussion, see “Certain Relationships and Related Party Transactions—Agreements with Entergy—Tax Sharing Agreement.” Our indemnification obligations to Entergy and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify Entergy and its subsidiaries and their respective officers and directors under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.

Our company and Entergy might not be able to engage in desirable strategic transactions and equity issuances following the distribution.

Entergy’s and our ability to engage in significant stock transactions could be limited or restricted after the distribution in order to preserve the tax treatment of the distribution with respect to Entergy. Even if the distribution, together with certain related transactions, otherwise qualifies as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, it would be taxable to Entergy (but not to Entergy shareholders) under Section 355(e) of the Code, if the distribution were deemed to be part of a plan (or series of related transactions) pursuant to which one or more persons acquired directly or indirectly stock representing a 50% or greater interest, by vote or value, in the stock of either Entergy or us. Current U.S. federal income tax law creates a presumption that the distribution would be taxable to Entergy, but not to its shareholders, if either we or Entergy were to engage in, or enter into an agreement to engage in, a transaction that would result in a 50% or greater change, by vote or value, in Entergy’s or our stock ownership during the four-year period that begins two years before the date of the distribution, unless it is established that the transaction is not pursuant to a plan or series of transactions related to the distribution. Treasury regulations generally provide that whether a transaction and a distribution are part of a plan is determined based on all of the facts and circumstances, including, but not limited to, certain specific factors. These restrictions may prevent Entergy and us from entering into transactions that might be advantageous to their respective shareholders, such as issuing equity securities to satisfy financing needs or acquiring businesses or assets with equity securities. Thus, even if the distribution, together with certain related transactions, qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, if acquisitions of Entergy stock or Enexus Energy stock after the distribution cause Section 355(e) of the Code to apply, Entergy would recognize taxable gain as described above, but the distribution would result in no recognition of income, gain or loss by any Entergy shareholder (except as a result of cash received in lieu of a fractional share of our common stock).

The Tax Sharing Agreement imposes liability on us if we take actions that cause the distribution to fail to qualify as a tax-free transaction, including, in certain cases, redeeming equity securities, selling or otherwise disposing of a substantial portion of our assets or acquiring businesses or assets with equity securities, in each case, for a period of 24 months from the day after the distribution. Moreover, the Tax Sharing Agreement generally provides that we will be responsible for any taxes imposed on Entergy or us as a result of the failure of the distribution, together with certain related transactions, to qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code if such failure is attributable to certain post-distribution actions taken by or in respect of us (including our subsidiaries) or our shareholders, such as the acquisition of us by a third party at a time and in a manner that would cause such failure. For more information, please see the sections entitled “The Separation—Material U.S. Federal Income Tax Consequences of the Distribution” and “Certain Relationships and Related Party Transactions—Agreements with Entergy—Tax Sharing Agreement.”

Risks Relating to our Common Stock

There is no existing market for our common stock, and a trading market that will provide you with adequate liquidity may not develop for our common stock. In addition, once our common stock begins trading, the market price of our shares may fluctuate widely.

There is currently no public market for our common stock. It is anticipated that, on or prior to the record date for the distribution, trading of shares of our common stock will begin on a “when-issued” basis and will continue up to and through the distribution date. However, there can be no assurance that an active trading market for our common stock will develop as a result of the distribution or be sustained in the future.

We cannot predict the prices at which our common stock may trade after the distribution. The market price of our common stock may fluctuate widely, depending upon many factors, some of which may be beyond our control, including:


	•	a shift in our investor base;


	•	the price and availability of capacity and/or energy in the markets we serve;

	•	our quarterly or annual earnings, or those of other companies in our industry;

	•	actual or anticipated fluctuations in our operating results due to the seasonality of our business and other factors related to our business;

	•	changes in accounting standards, policies, guidance, interpretations or principles;

	•	announcements by us or our competitors of significant acquisitions or dispositions;

	•	the failure of securities analysts to cover our common stock after the distribution;

	•	changes in earnings estimates by securities analysts or our ability to meet those estimates;

	•	the operating and stock price performance of other comparable companies;

	•	overall market fluctuations; and

	•	general economic conditions.

Stock markets in general have experienced volatility that has often been unrelated to the operating or financial performance of a particular company. These broad market fluctuations may adversely affect the trading price of our common stock.

Substantial sales of common stock may occur in connection with this distribution, which could cause our stock price to decline.

The shares of our common stock that Entergy distributes to its shareholders generally may be sold immediately in the public market. Although we have no actual knowledge of any plan or intention on the part of any shareholder to sell our common stock following the separation, it is possible that some Entergy shareholders, including possibly some of our largest shareholders, may sell our common stock received in the distribution for reasons such as that our business profile or market capitalization as a separate, publicly-traded company does not fit their investment objectives. Moreover, index funds tied to the Standard & Poor’s 500 Index, the Russell 1000 Index and other indices hold shares of Entergy common stock. To the extent our common stock is not included in these indices after the distribution, certain of these index funds may likely be required to sell the shares of our common stock that they receive in the distribution. The sales of significant amounts of our common stock or the perception in the market that this will occur may result in the lowering of the market price of our common stock.

Provisions in our certificate of incorporation, our by-laws, Delaware law and certain of the agreements we will enter into as part of the separation may prevent or delay an acquisition of our company, which could decrease the trading price of our common stock.

Our certificate of incorporation, by-laws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include, among others:


	•	a board of directors that is divided into three classes with staggered terms;

	•	rules regarding how shareholders may present proposals or nominate directors for election at shareholder meetings;

	•	the right of our board of directors to issue preferred stock without shareholder approval; and

	•	limitations on the right of shareholders to remove directors.

Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. For more information, see the section entitled “Description of Enexus Energy Stock—Certain Anti-takeover Effects.”

We believe these provisions are important for a new public company and protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make our company immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition that our board of directors determines is not in the best interests of our company and our shareholders.

In addition, certain provisions in the agreements we will enter into as part of the separation may prevent or delay an acquisition of our company. The Operating Agreements and the Joint Venture Agreements provide that if EquaGen is operating four or fewer of our nuclear power plants, then the remaining Operating Agreements are terminated if the Board of EquaGen has not exercised its right to override the automatic termination. If the Board of EquaGen decided to not override automatic termination of the Operating Agreements, we may be obligated (if Entergy elects to exercise its rights under the Joint Venture Agreements) to either purchase the subsidiaries of EquaGen that carry on its “third party” business, or purchase Entergy’s 50% membership interest in EquaGen. For more information, see the section entitled “Certain Relationships and Related Party Transactions — Agreements with Entergy — Joint Venture Agreements — Exercise Event.” We may not have sufficient cash to fulfill these obligations, if they are triggered, or we may experience pressure on our liquidity as a result of the obligation to purchase either the subsidiaries of EquaGen or Entergy’s 50% membership interest in EquaGen. Because these provisions survive the acquisition of our company by a third party, a potential acquirer might wish to forgo an acquisition if it wished to terminate the Operating Agreements but not be obligated to purchase Entergy’s 50% membership interest in EquaGen or EquaGen’s “third-party business” subsidiaries.

FORWARD-LOOKING STATEMENTS

Our reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include those set forth in the section entitled “Risk Factors,” as well as the following:


	•	our ability to manage our operation and maintenance costs, including through EquaGen;

	•	changes in regulation, including the application of market power criteria by the FERC;

	•	the economic climate and, particularly, growth in the Northeast United States;

	•	variations in weather and the occurrence of storms and disasters;

	•	the performance of our generating plants and, particularly, the capacity factors at our nuclear generating facilities;

	•	changes in the financial markets during the periods covered by the forward-looking statements, particularly those affecting the availability of capital and our ability to refinance existing debt, execute our share repurchase program and fund investments and acquisitions;

	•	actions of rating agencies, including the ratings of debt, general corporate ratings and changes in the rating agencies’ ratings criteria;

	•	changes in inflation and interest rates;

	•	our ability to develop and execute on a point of view regarding future prices of energy-related commodities;

	•	our ability to purchase and sell assets at attractive prices and on other attractive terms;

	•	prices for power generated by our generating facilities, the ability to hedge, sell power forward or otherwise reduce the market price risk associated with those facilities, and our ability to meet credit support requirements for fuel and power supply contracts;

	•	volatility and changes in markets for electricity, natural gas, uranium and other energy-related commodities;

	•	changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of nuclear generating facilities, particularly those in the Northeast United States;

	•	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal;

	•	resolution of pending or future applications for license extensions or modifications of nuclear generating facilities;

	•	changes in law resulting from new federal or state energy legislation;

	•	changes in environmental, safety, tax and other laws to which we and our subsidiaries are subject;

	•	advances in technology;

	•	the potential effects of threatened or actual terrorism and war;

	•	the effects of our strategies to reduce tax payments;

	•	the effects of litigation and government investigations;


	•	changes in accounting standards and corporate governance;

	•	our and EquaGen’s ability to attract and retain talented management and directors;

	•	the outcomes of litigation and regulatory investigations, proceedings or inquiries;

	•	the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;

	•	declines in the market prices of equity securities and resulting funding requirements for our defined benefit pension plans;

	•	changes in the results of the decommissioning trust fund earnings or in the timing of or cost to decommission;

	•	the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

	•	the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the non-utility nuclear business and any related actions for indemnification made pursuant to the Separation and Distribution Agreement;

	•	our ability to operate effectively as a separate, publicly-traded company; and

	•	the costs associated with becoming compliant with the Sarbanes-Oxley Act of 2002 as a stand-alone company and the consequences of failing to implement effective internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002 by the date that we must comply with that section of the Sarbanes-Oxley Act.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than we have described. We undertake no obligation, except as may otherwise be required by the federal securities laws, to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

THE SEPARATION

General

On November 3, 2007, the board of directors of Entergy initially approved a plan to separate its non-utility nuclear business into a separate, publicly-traded company, and for our company to enter into a nuclear services joint venture with Entergy, with equal percentage ownership.

In furtherance of this plan, on , 2008, Entergy’s board of directors approved the distribution of all of the shares of our common stock held by Entergy to holders of Entergy common stock. The distribution of the shares of our common stock will take place on , 2008. On the distribution date, each holder of Entergy common stock will receive share(s) of our common stock for each share of Entergy common stock held at the close of business on the record date, as described below. Following the distribution, Entergy shareholders will own 100% of our common stock.

You will not be required to make any payment, surrender or exchange your shares of Entergy common stock or take any other action to receive your shares of our common stock.

The distribution of our common stock as described in this information statement is subject to the satisfaction or waiver of certain conditions, including final approval of Entergy’s board of directors. We cannot provide any assurances that the distribution will be completed or approved by Entergy’s board of directors. For a more detailed description of these conditions, see the section entitled “—Conditions to the Distribution.”

Joint Venture

We will establish a joint venture with equal ownership, referred to in this information statement as EquaGen, with Entergy. Entergy Nuclear, Inc., currently a wholly-owned subsidiary of Entergy, will become a limited liability company and change its name to EquaGen LLC. We and Entergy will each own a 50% interest in EquaGen immediately prior to completion of the distribution of our common stock. EquaGen is expected to operate the nuclear assets owned by us, and to provide certain services to the regulated nuclear utility operations of Entergy and to third parties. EquaGen will allow certain nuclear operations expertise currently in place at each of Entergy’s nuclear power plant facilities to be accessible by both us and Entergy after the separation.

Upon completion of the transactions contemplated by the Joint Venture Agreements, EquaGen will own:


	•	Entergy Nuclear Operations, currently a wholly-owned subsidiary of Entergy and the current NRC-licensed operator of our nuclear power plants. Entergy Nuclear Operations is expected to become a Delaware limited liability company and change its name to EquaGen Nuclear LLC in connection with the separation. Entergy Nuclear Operations shall remain the operator of our plants after the separation; and

	•	TLG Services, Inc., currently a wholly-owned subsidiary of Entergy that provides decommissioning and other consulting services to Entergy and to other companies in the nuclear industry. TLG Services, Inc. is expected to become a Delaware limited liability company and change its name to TLG Services, LLC in connection with the separation.

The Number of Shares You Will Receive

For each share of Entergy common stock that you owned at the close of business on , 2008, the record date, you will receive share(s) of our common stock on the distribution date. Entergy will not distribute any fractional shares of our common stock to its shareholders. Instead, the transfer agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds of the sales pro rata to each holder of Entergy Common Stock who otherwise would have been entitled to receive a fractional share in the distribution. Recipients of

cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares.

When and How You Will Receive the Distributed Shares

Entergy will distribute the shares of our common stock on , 2008, the distribution date. BNY Mellon Shareowner Services will serve as transfer agent and registrar for our common stock and as distribution agent in connection with the distribution.

If you own Entergy common stock as of the close of business on the record date, the shares of our common stock that you are entitled to receive in the distribution will be issued electronically, as of the distribution date, to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. Registration in book-entry form refers to a method of recording stock ownership when no physical share certificates are issued to shareholders, as is the case in this distribution.

If you sell shares of Entergy common stock in the “regular-way” market prior to the distribution date, you will be selling your right to receive shares of our common stock in the distribution. For more information please see the section entitled “—Trading between the Record Date and through the Distribution Date.”

Commencing on or shortly after the distribution date, if you hold physical stock certificates that represent your shares of Entergy common stock and you are the registered holder of the Entergy shares represented by those certificates, the distribution agent will mail to you an account statement that indicates the number of shares of our common stock that have been registered in book-entry form in your name. If you have any questions concerning the mechanics of having shares of our common stock registered in book-entry form, we encourage you to contact BNY Mellon Shareowner Services at the address and telephone number set forth on page 16 of this information statement.

Most Entergy shareholders hold their shares of Entergy common stock through a bank or brokerage firm. In such cases, the bank or brokerage firm would be said to hold the stock in “street name” and ownership would be recorded on the bank’s or brokerage firm’s books. If you hold your Entergy common stock through a bank or brokerage firm, your bank or brokerage firm will credit your account for the shares of our common stock that you are entitled to receive in the distribution. If you have any questions concerning the mechanics of having shares of our common stock held in “street name,” we encourage you to contact your bank or brokerage firm.

BNY Mellon Shareowner Services, as distribution agent, will not deliver any fractional shares of our common stock in connection with the distribution. Instead, BNY Mellon Shareowner Services will aggregate all fractional shares and sell the shares in the open market at prevailing market prices on behalf of the holders who otherwise would be entitled to receive fractional shares. The aggregate net cash proceeds of these sales, which generally will be taxable for U.S. federal income tax purposes, will be distributed pro rata (based on the fractional shares such holder would otherwise be entitled to receive) to each holder who otherwise would have been entitled to receive a fractional share in the distribution. For more information on the tax consequences, please see the section entitled “—Material U.S. Federal Income Tax Consequences of the Distribution” below for an explanation of the tax consequences of the distribution. If you physically hold Entergy common stock certificates and are the registered holder, you will receive a check from the distribution agent in an amount equal to your pro rata share of the aggregate net cash proceeds of the sales. We estimate that it will take approximately two weeks from the distribution date for the distribution agent to complete the distributions of the aggregate net cash proceeds. If you hold your Entergy stock through a bank or brokerage firm, your bank or brokerage firm will receive on your behalf your pro rata share of the aggregate net cash proceeds of the sales and will electronically credit your account for you.

Results of the Separation

After our separation from Entergy, we will be a separate, publicly-traded company. Immediately following the distribution, we expect to have approximately shareholders of record, based on the

number of registered shareholders of Entergy common stock on , 2008, and approximately shares of our common stock outstanding. The actual number of shares to be distributed will be determined on the record date and will reflect any exercise of Entergy options between the date the Entergy board of directors declares the dividend for the distribution and the record date for the distribution.

Before the separation, we will enter into the Separation and Distribution Agreement, the Joint Venture Agreements, and several other agreements with Entergy or EquaGen to effect the separation and provide a framework for our relationships with Entergy, Entergy’s other businesses and EquaGen after the separation. These agreements will govern the relationship among us, EquaGen, Entergy and Entergy’s other businesses subsequent to the completion of the separation and provide for the allocation among us, EquaGen, Entergy and Entergy’s other businesses, of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the non-utility nuclear business attributable to periods prior to, at and after our separation from Entergy. For a more detailed description of these agreements, see the section entitled “Certain Relationships and Related Party Transactions.”

The distribution will not affect the number of outstanding shares of Entergy common stock or any rights of Entergy shareholders.

Share Purchase and Dividend Reinvestment Plan

For shareholders who hold shares of Entergy’s common stock in Entergy’s share purchase and dividend reinvestment plan, the shares of our common stock such shareholders are entitled to receive in the distribution will be distributed to your account for Entergy’s share purchase and dividend reinvestment plan.

Incurrence of Debt

We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business. Entergy has informed us that it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any cash proceeds from the portion of our debt securities that are transferred to Entergy. The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement. Additionally, we intend to enter into one or more credit facilities or other financing arrangements meant to support our working capital and general corporate needs and collateral obligations arising from hedging and normal course of business requirements.

For more information on our planned financing arrangements, please see the sections entitled “Unaudited Pro Forma Financial Information of Enexus Energy,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and “Description of Material Indebtedness.”

Material U.S. Federal Income Tax Consequences of the Distribution

The following is a summary of material U.S. federal income tax consequences relating to the distribution by Entergy. This summary is based on the Code, the Treasury regulations promulgated thereunder, and interpretations of the Code and the Treasury regulations, including proposed regulations, by the courts and the IRS, in effect as of the date hereof, and all of which are subject to change, possibly with retroactive effect. This summary does not discuss all the tax considerations that may be relevant to Entergy shareholders in light of their particular circumstances, nor does it address the consequences to Entergy shareholders subject to special treatment under the U.S. federal income tax laws (such as non-U.S. persons, insurance companies, dealers or brokers in securities or currencies, tax-exempt organizations, financial institutions, mutual funds, pass-through entities and investors in such entities, holders who hold their shares as a hedge or as part of a hedging, straddle, conversion, synthetic security, integrated investment or other risk-reduction transaction or

who are subject to alternative minimum tax or holders who acquired their shares upon the exercise of employee stock options or otherwise as compensation). In addition, this summary does not address the U.S. federal income tax consequences to those Entergy shareholders who do not hold their Entergy common stock as a capital asset. Finally, this summary does not address any state, local or foreign tax consequences. ENTERGY SHAREHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL, STATE AND LOCAL AND NON-U.S. TAX CONSEQUENCES OF THE DISTRIBUTION TO THEM.

The distribution is conditioned upon Entergy’s receipt of a private letter ruling from the IRS and the opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, in each case, to the effect that the distribution will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. Assuming the distribution so qualifies: (i) no gain or loss will be recognized by (and no amount will be included in the income of) Entergy common shareholders upon their receipt of shares of Enexus Energy common stock in the distribution; (ii) any cash received in lieu of fractional share interests in Enexus Energy will give rise to gain or loss equal to the difference between the amount of cash received and the tax basis allocable to the fractional share interests (determined as described below), and such gain or loss will be capital gain or loss if the Entergy common stock on which the distribution is made is held as a capital asset on the date of the distribution; (iii) the aggregate basis of the Entergy common stock and the Enexus Energy common stock in the hands of each Entergy common shareholder after the distribution (including any fractional interests to which the shareholder would be entitled) will equal the aggregate basis of Entergy common stock held by the shareholder immediately before the distribution, allocated between the Entergy common stock and the Enexus Energy common stock in proportion to the relative fair market value of each on the date of the distribution; and (iv) the holding period of the Enexus Energy common stock received by each Entergy common shareholder will include the holding period at the time of the distribution for the Entergy common stock on which the distribution is made, provided that the Entergy common stock is held as a capital asset on the date of the distribution.

A private letter ruling from the IRS generally is binding on the IRS. The IRS, however, will not rule on some requirements necessary for tax-free treatment under Section 355 of the Code. Therefore, in addition to obtaining the ruling from the IRS, Entergy has made it a condition to the distribution that Entergy obtain an opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, that the distribution will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The opinion will rely on the ruling as to matters covered by the ruling. In addition, the opinion will be dependent on, among other things, certain assumptions and representations as to factual matters made by Entergy and us. The opinion will not be binding on the IRS or the courts, and the IRS or the courts may not agree with the opinion.

Notwithstanding receipt by Entergy of the ruling and opinion of counsel, the IRS could assert that the distribution does not qualify for tax-free treatment for U.S. federal income tax purposes. If the IRS’ challenge to tax-free treatment were successful, our initial public shareholders and Entergy could be subject to significant U.S. federal income tax liability. In general, Entergy would be subject to tax as if it had sold the common stock of our company in a taxable sale for its fair market value and our initial public shareholders would be subject to tax as if they had received a taxable distribution equal to the fair market value of our common stock that was distributed to them. In addition, even if the distribution were to otherwise qualify under Section 355 of the Code, it may be taxable to Entergy (but not to Entergy’s shareholders) under Section 355(e) of the Code, if the distribution were later deemed to be part of a plan (or series of related transactions) pursuant to which one or more persons acquire directly or indirectly stock representing a 50% or greater interest in Entergy or us. For this purpose, any acquisitions of Entergy stock or of our common stock within the period beginning two years before the distribution and ending two years after the distribution are presumed to be part of such a plan, although we or Entergy may be able to rebut that presumption.

In connection with the distribution, we and Entergy will enter into a Tax Sharing Agreement pursuant to which we will agree to be responsible for certain liabilities and obligations following the distribution. In general, under the terms of the Tax Matters Agreement, if the distribution failed to qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code (including as a result of

Section 355(e) of the Code) and such failure was not the result of actions taken after the distribution by Entergy or us, we and Entergy would be responsible for % and %, respectively, of any taxes imposed on Entergy as consequence. If the failure was the result of actions taken after the distribution by Entergy or us, the party responsible for the failure would be responsible for all taxes imposed on Entergy as a consequence. For a more detailed discussion, see “Certain Relationships and Related Party Transactions—Agreements with Entergy—Tax Sharing Agreement.” Our indemnification obligations to Entergy and its subsidiaries, officers and directors are not limited in amount or subject to any cap. If we are required to indemnify Entergy and its subsidiaries and their respective officers and directors under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.

U.S. Treasury regulations require that, if you are a holder of Entergy common stock who receives our common stock in the distribution and, immediately prior to the distribution, own:


	•	at least 5% of the total outstanding stock of Entergy, or

	•	securities of Entergy with an aggregate tax basis of $1,000,000 or more,

then you must attach a statement relating to the distribution to your federal tax return for the year in which the distribution occurs.

Information and backup withholding will apply with respect to cash proceeds received in lieu of a fractional share of our common stock only if such proceeds equal or exceed $20.

THE FOREGOING IS A SUMMARY OF CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE DISTRIBUTION UNDER CURRENT LAW AND IS FOR GENERAL INFORMATION ONLY. THE FOREGOING DOES NOT PURPORT TO ADDRESS ALL U.S. FEDERAL INCOME TAX CONSEQUENCES OR TAX CONSEQUENCES THAT MAY ARISE UNDER THE TAX LAWS OF OTHER JURISDICTIONS OR THAT MAY APPLY TO PARTICULAR CATEGORIES OF SHAREHOLDERS. EACH ENTERGY SHAREHOLDER SHOULD CONSULT ITS TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF THE DISTRIBUTION TO SUCH SHAREHOLDER, INCLUDING THE APPLICATION OF U.S. FEDERAL, STATE, LOCAL AND FOREIGN TAX LAWS, AND THE EFFECT OF POSSIBLE CHANGES IN TAX LAWS THAT MAY AFFECT THE TAX CONSEQUENCES OF THE DISTRIBUTION DESCRIBED ABOVE.

Market for Common Stock

There is currently no public market for our common stock. A condition to the distribution is the listing on the New York Stock Exchange of our common stock. Prior to the distribution, we intend to apply to list our common stock on the New York Stock Exchange under the ticker symbol .

Trading between the Record Date and through the Distribution Date

Beginning on or shortly before the record date and continuing up to and through the distribution date, we expect that there will be two markets in Entergy common stock: a “regular-way” market and an “ex-distribution” market. Shares of Entergy common stock that trade on the regular way market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade on the ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if you own shares of Entergy common stock at the close of business on the record date, and you sell those shares of Entergy common stock in the “regular-way” market on or before the distribution date, you will be selling your right to receive shares of Enexus Energy common stock in the distribution. If you own shares of Entergy common stock at the close of business on the record date and sell those shares on the “ex-distribution” market on or before the distribution date, you will still receive the shares of our common stock that you would be entitled to receive pursuant to your ownership of the shares of Entergy common stock on the record date.

Furthermore, beginning on or shortly before the record date and continuing up to and through the distribution date, we expect that there will be a “when-issued” market in our common stock. “When-issued”

trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The “when-issued” trading market will be a market for shares of our common stock that will be distributed to Entergy shareholders on the distribution date. If you owned shares of Entergy common stock at the close of business on the record date, you would be entitled to shares of our common stock distributed pursuant to the distribution. You may trade this entitlement to shares of our common stock, without trading the shares of Entergy common stock you own, on the “when-issued” market. On the first trading day following the distribution date, “when issued” trading with respect to our common stock will end and “regular-way” trading will begin.

Conditions to the Distribution

We expect that the distribution will be effective on , 2008, the distribution date, provided that, among other conditions described in this information statement, the following conditions shall have been satisfied or, if permissible under the Separation and Distribution Agreement, waived by Entergy:


	•	the SEC shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Exchange Act, and no stop order relating to the registration statement is in effect;

	•	all permits, registrations and consents required under the securities or blue sky laws of states or other political subdivisions of the United States or of other foreign jurisdictions in connection with the distribution shall have been received;

	•	all required federal and state regulatory approvals (including approvals of the NRC, FERC, New York State Public Service Commission and Vermont Public Service Board) in connection with the distribution and related transactions (including the internal reorganizations by us and Entergy, the formation of EquaGen and debt financing transactions preceding the distribution) shall have been received;

	•	the debt financing transactions shall have been completed;

	•	Entergy shall have received a private letter ruling from the IRS substantially to the effect that the distribution, together with certain related transactions, qualifies as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

	•	Entergy shall have received a legal opinion of Entergy’s tax counsel, Cooley Godward Kronish LLP, substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

	•	the listing of our common stock on the New York Stock Exchange shall have been approved, subject to official notice of issuance; and

	•	no order, injunction or decree issued by any court of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution or any of the transactions related thereto, including the debt financing, the transfers of assets and liabilities contemplated by the Separation and Distribution Agreement or the formation of EquaGen, shall be in effect.

The fulfillment of the foregoing conditions does not create any obligation on Entergy’s part to effect the distribution, and the Entergy board of directors has reserved the right, in its sole discretion, to amend, modify or abandon the distribution and related transactions at any time prior to the distribution date. Entergy has the right not to complete the distribution if, at any time, the Entergy board of directors determines, in its sole discretion, that the distribution is not in the best interests of Entergy or its shareholders or that market conditions are such that it is not advisable to separate the non-utility nuclear business from Entergy.

Regulatory Approvals Necessary to Effect the Separation

Nuclear Regulatory Commission

Certain of the internal reorganization and financing transactions that are to precede the separation, including the indirect transfer of the NRC licenses to EquaGen and Enexus Energy, respectively, require the prior written approval of the NRC under the Atomic Energy Act of 1954, as amended.

Entergy Nuclear Operations, the current NRC-licensed operator of our six operating nuclear power plants, filed an application in July 2007 with the NRC seeking indirect transfer of control of the operating licenses for our six operating nuclear power plants, and supplemented that application in December 2007 to incorporate the separation. In the December 2007 supplement to the NRC application, Entergy Nuclear Operations provided additional information regarding the distribution, organizational structure, technical and financial qualifications and general corporate information. The NRC published a notice in the Federal Register establishing a period for the public to submit a request for hearing or petition to intervene in a hearing proceeding. The NRC notice period expired on February 5, 2008 and two petitions to intervene in the hearing proceeding were filed before the deadline. Each of the petitions opposes the NRC’s approval of the license transfer on various grounds, including contentions that the approval request is not adequately supported regarding the basis for the proposed structure, the adequacy of decommissioning funding and the adequacy of financial qualifications. Entergy submitted answers to the petitions on March 31 and April 8, and the NRC or a presiding officer designated by the NRC will determine whether a hearing will be granted. If a hearing is granted, the NRC is expected to issue a procedural schedule providing for limited discovery, written testimony and a legislative-type hearing. Under the NRC’s procedural rules for license transfer approvals, the NRC Staff will continue to review the application, prepare a Safety Evaluation analyzing the proposed license transfer and issue an approval or denial without regard to whether or not a hearing request is pending or has been granted. Thus resolution of the hearing requests is not a prerequisite to obtaining the required NRC approval.

Federal Energy Regulatory Commission

The indirect transfer of the assets of the non-utility nuclear business to Enexus Energy will require the approval of the FERC under Section 203 of the Federal Power Act. On February 21, 2008, an application was filed with the FERC requesting approval for the indirect disposition and transfer of control of jurisdictional facilities of a public utility. The review of the filing by the FERC will be focused on determining that the transaction will have no adverse effects on competition, wholesale or retail rates and on federal and state regulation. Also, the FERC will seek to determine that the transaction will not result in cross-subsidization by a regulated utility or the pledge or encumbrance of utility assets for the benefit of a non-utility associate company.

State Regulatory Approvals

The separation and related transactions require the approval of the Vermont Public Service Board. On January 28, 2008, Entergy Nuclear Vermont Yankee (which owns Vermont Yankee) and Entergy Nuclear Operations requested approval from the Vermont Public Service Board for the indirect transfer of control, consent to pledge assets, issue guarantees and assign material contracts, amendment to certificate of public good to reflect a name change and replacement of guaranty and substitution of a credit support agreement for Vermont Yankee.

Two Vermont utilities that buy power from Vermont Yankee, the regional planning commission for the area served by Vermont Yankee, a municipality in which the Vermont Yankee training center is located, the union that represents certain Vermont Yankee employees and two unions that represent certain employees at the Pilgrim plant in Massachusetts petitioned to intervene. Entergy opposed intervention by the Pilgrim unions but did not object to the other intervention requests. Although the Pilgrim unions’ petition to intervene was denied, the Pilgrim unions filed for reconsideration or, in the alternative, for participation as an amicus curiae, and the Vermont Public Service Board has allowed the unions to participate as an amicus curiae.

Discovery is underway in this proceeding, in which parties can ask questions about or request the production of documents related to the transaction.

On May 7, 2008, the Vermont governor vetoed legislation approved by the Vermont General Assembly in its 2008 session that would have required Entergy to fund, beyond current NRC requirements, the decommissioning trust fund for Vermont Yankee as a precondition to the Vermont Public Service Board’s approval of the separation. In its proposed form, the legislation would have required a determination that Vermont Yankee’s decommissioning trust fund and financial guarantees available solely for the purpose of decommissioning were adequate to pay for a complete and immediate decommissioning of Vermont Yankee as of the date of any acquisition of control, including our acquisition of control of Vermont Yankee in connection with the separation.

On January 28, 2008, the owners of our FitzPatrick, Indian Point 2 and Indian Point 3 nuclear power plants, Entergy Nuclear FitzPatrick, LLC, Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC, as well as Entergy Nuclear Operations, and us, filed a petition with the New York Public Service Commission requesting a declaratory ruling regarding corporate reorganization or in the alternative an order approving the transaction and an order approving debt financing. Petitioners also requested confirmation that the corporate reorganization will not have an effect on Entergy Nuclear FitzPatrick’s, Entergy Nuclear Indian Point 2’s, Entergy Nuclear Indian Point 3’s, and Entergy Nuclear Operations, Inc.’s status as lightly regulated entities in New York, given that they will continue to be competitive wholesale generators. The New York Attorney General has filed an objection to our separation from Entergy and to the transfer of our FitzPatrick and Indian Point Energy Center nuclear power plants, arguing that the debt associated with the spin-off could threaten access to adequate financial resources for our nuclear power plants, that Entergy could potentially be able to terminate revenue sharing agreements with the New York Power Authority (NYPA), the entity from which Entergy purchased the FitzPatrick and Indian Point 3 nuclear power plants and because the New York Attorney General believes Entergy must file an environmental impact statement assessing the proposed corporate restructuring.

Internal Reorganization Prior to the Distribution


	•	Internal business transfers. Entergy will reorganize its corporate structure by means of transfers of equity interests of certain of its subsidiaries so that we hold all of the assets of the non-utility nuclear business and certain assets in the non-utility nuclear services business, and EquaGen holds primarily the non-utility nuclear services business.

	•	EquaGen. Entergy and we will each own a 50% membership interest in EquaGen.

	•	Debt financing. We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities and enter into one or more credit facilities or other financing arrangements.

	•	Repayment of intercompany debt, transfer to Entergy. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business.

Set forth below are simplified diagrams of Entergy prior to the separation and of Entergy and us after the separation. Not all subsidiaries and businesses are shown.

Reasons for the Separation

The Entergy board of directors regularly reviews Entergy’s various businesses to ensure that Entergy’s resources are being put to use in a manner that is in the best interests of Entergy and its shareholders. Entergy believes that the separation of the non-utility nuclear business is the best way to unlock the full value of Entergy’s businesses in both the short- and long-term and provides each of Entergy and us with certain opportunities and benefits. The following are the factors that Entergy’s board of directors considered in approving the separation:


	•	Enables equity investors to invest directly in our business. There are divergent public market valuation methodologies for regulated utilities and merchant power companies such as us. As a result, if separately traded, Entergy’s board of directors believes the combined market capitalizations of the regulated utility business and us may be higher than if these two businesses remain combined under Entergy. Moreover, Entergy’s board of directors believes that the market has great interest in a separate nuclear business because it presents a unique investment opportunity in a publicly-traded stand-alone, virtually emissions-free nuclear generating company in the United States. Last, Entergy’s board of directors believes that certain equity investors may want to invest in companies that are focused on only one industry and that the demand for each company may increase the demand for each company’s shares relative to the demand for Entergy’s shares.

	•	Optimizes capital structure. Historically, the non-utility nuclear business of Entergy has held a small amount of debt in relation to its revenues. Entergy’s board of directors believes the separation of our company from Entergy will allow us to optimize the amount of our leverage and consequently reduce the cost of issuing equity and debt securities for both our company and Entergy without adversely affecting the credit ratings and future earnings of Entergy’s regulated utility business.

	•	Isolates the commodity and other risks of the non-utility nuclear business from the regulated utility business. As currently operated, the non-utility nuclear business of Entergy is hedged against certain risks, including, in the near term, the volatility in the price of power, because being substantially unhedged could adversely affect Entergy’s near term earnings, cash flows and credit ratings if the price of power fell significantly. Entergy’s board of directors believes that separating our business from the regulated utility business of Entergy will give our management the flexibility to manage our risk unfettered by concerns about the impact of our hedging strategies on the regulated utility operations of Entergy.

	•	Creates more effective management incentives. Entergy currently uses stock options, phantom stock plans, and stock rights as incentive compensation to retain and motivate executives and key employees. These plans are generally tied to the price of Entergy common stock. Because the value of Entergy stock represents a blend of both the regulated utility operations and the non-utility nuclear operations, value creation in one business can be offset by decreased value in the other business, making Entergy stock an imperfect tool for rewarding and retaining key employees in either business. The separation will allow for more focused stock compensation plans in each of the regulated utility operations and the non-utility nuclear operations.

	•	Allows us and Entergy to focus on opportunities for each company, including M&A opportunities. As the utility industry continues to restructure, Entergy’s board of directors believes there may be opportunities for additional nuclear power plant acquisitions. Separating the non-utility nuclear operations from Entergy’s utility operations will create a public market for the stock and securities of our company, which Entergy’s board of directors believes will allow potential plant sellers various ways to participate in our company by receiving shares of our stock or other securities as compensation for the sale of a power plant. Entergy’s board of directors believes this focused participation could not be accomplished by using Entergy stock.

Neither we nor Entergy can assure you that, following the separation, any of these benefits will be realized to the extent anticipated or at all.

In view of the wide variety of factors considered in connection with the evaluation of the separation and the complexity of these matters, Entergy’s board of directors did not find it useful to, and did not attempt to, quantify, rank or otherwise assign relative weights to the factors considered. The individual members of Entergy’s board of directors likely may have given different weights to different factors.

Reason for Furnishing this Information Statement

This information statement is being furnished solely to provide information to Entergy shareholders who are entitled to receive shares of our common stock in the distribution. The information statement is not, and is not to be construed as, an inducement or encouragement to buy, hold or sell any of our securities or securities of Entergy. We believe that the information in this information statement is accurate in all material respects as of the date set forth on the cover. Changes may occur after that date and, except as may be required by the federal securities laws, neither Entergy nor we undertake any obligation to update such information.

CAPITALIZATION

The following table presents our historical cash and cash equivalents and capitalization at December 31, 2007 and our unaudited pro forma cash and cash equivalents and capitalization at that date reflecting the following transactions as if they had occurred on December 31, 2007:


	•	The internal reorganization of Entergy’s corporate structure by means of transfers of equity interests of certain of its subsidiaries so that we hold substantially all of the assets of the non-utility nuclear business.

	•	Entergy’s transfer to us of $1.0 billion in cash as a capital contribution.

	•	Entergy’s transfer to us of a net amount of $1.0 billion of loans payable to associated companies.

	•	The issuance of and transfer by us to Entergy of $3.0 billion of our debt securities. We will not receive any cash proceeds from the portion of our debt securities that are transferred to Entergy.

	•	The issuance by us of $1.5 billion of debt securities from which we will receive the proceeds.

	•	The repayment by us of a net amount of $2.2 billion of loans payable to associated companies along with interest that had accrued thereon.

The unaudited pro forma adjustments reflect the expected effects of these events that are directly attributable to the separation and related transactions, that are expected to have a continuing impact on Enexus Energy and that are factually supportable.


	As of December 31, 2007
	Historical		Pro Forma
	(in thousands)

Cash and cash equivalents		$428,859		$795,260

Loans payable - associated companies		$1,256,627		$-

Long-term debt (excluding current maturities)		210,732		4,710,732

Shareholders’ Equity		2,302,583		(669,124	)

Total capitalization		$3,769,942		$4,041,608

UNAUDITED PRO FORMA FINANCIAL INFORMATION OF ENEXUS ENERGY

The following tables present our pro forma combined financial information and should be read in conjunction with our historical combined financial statements and the related notes, “Selected Historical Combined Financial Data” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition” included elsewhere in this information statement.

The unaudited pro forma combined financial statements presented below have been derived from the audited historical combined financial statements for the year ended December 31, 2007. The pro forma adjustments and notes to the pro forma combined financial statements give effect to the separation and related transactions.

The unaudited pro forma condensed combined information is for illustrative and informational purposes only and is not intended to represent, or be indicative of, what Enexus Energy’s results of operations or financial position would have been had the separation and related transactions occurred on the dates indicated. The unaudited pro forma condensed combined financial information also should not be considered representative of Enexus Energy’s future financial position or results of operations.

The unaudited pro forma condensed combined income statement for the year ended December 31, 2007 has been prepared as if the separation had occurred on January 1, 2007. The unaudited pro forma condensed combined balance sheet as of December 31, 2007 has been prepared as if the separation had occurred on December 31, 2007. The unaudited pro forma adjustments reflect the expected effects of events that are directly attributable to the separation and related transactions, are expected to have a continuing effect on Enexus Energy and are factually supportable.

Unaudited Pro Forma Condensed Combined Balance Sheet
As of December 31, 2007
(in thousands)


			Pro Forma
	Historical		Adjustments					Pro Forma

ASSETS

Cash and cash equivalents		$428,859		$964,689		(1	)		$795,260
				(598,288	)	(2	)
Other current assets		599,153		318,875		(1	)		598,624
				(319,404	)	(2	)
Decommissioning trust funds		1,937,601		-					1,937,601

Total property, plant, and equipment		3,672,306		-					3,672,306
Less - accumulated depreciation and amortization		309,308		-					309,308

Property, plant, and equipment - net		3,362,998		-					3,362,998

Other assets		689,508		36,259		(1	)		744,517
				18,750		(2	)

TOTAL ASSETS		$7,018,119		$420,881					$7,439,000



LIABILITIES AND SHAREHOLDERS’ EQUITY

Loans payable - associated companies		$1,256,627		$922,893		(1	)		$-
				(2,179,520	)	(2	)
Other current liabilities		530,883		176,768		(1	)		519,584
				(234,422	)	(2	)
				46,355		(3	)
Accumulated deferred income taxes		780,741		(229,314	)	(1	)		924,797
				-		(2	)
				373,370		(3	)
Decommissioning		1,141,552		-					1,141,552
Long-term debt		210,732		3,000,000		(1	)		4,710,732
				1,500,000		(2	)
Other non-current liabilities		795,001		16,458		(1	)		811,459
				-
Shareholders’ Equity		2,302,583		(2,566,982	)	(1	)		(669,124	)
				15,000		(2	)
				(419,725	)	(3	)

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$7,018,119		$420,881					$7,439,000

Unaudited Pro Forma Condensed Combined Income Statement
For the Year Ended December 31, 2007
(in thousands, except for per share data)


				Pro Forma
	Historical			Adjustments				Pro Forma

OPERATING REVENUES

Operating Revenues		$2,029,666		$	-				$2,029,666


OPERATING EXPENSES

Operation and Maintenance:
Fuel and fuel-related expenses		168,860			-				168,860
Nuclear refueling outage expenses		105,885			-				105,885
Other operation		645,903			-				645,903
Maintenance		138,480			-				138,480
Depreciation and amortization		99,265			-				99,265
Decommissioning expense		78,607			-				78,607
Taxes other than income taxes		78,550			-				78,550

TOTAL		1,315,550			-				1,315,550


OPERATING INCOME		714,116			-				714,116


OTHER INCOME

Interest and dividend income		102,842			-				102,842
Miscellaneous - net		(715	)		(29,000	)	(5)		(29,715	)

TOTAL		102,127			(29,000	)			73,127


INTEREST EXPENSE

Interest to associated companies		103,450			(83,434	)	(2)		-
					(20,016	)	(4)
Interest expense - other		14,722			372,600		(1),(2)		417,634
					30,312		(4)

TOTAL		118,172			299,462				417,634


INCOME BEFORE INCOME TAXES		698,071			(328,462	)			369,609

Income taxes		212,023			(114,210	)	(1),(2),(3),(4),(5)		97,813


NET INCOME		$486,048		$	(214,252	)			$271,796

Basic and diluted pro forma net income per common share(6)									$1.38

Notes to Unaudited Pro Forma Financial Information

(1) Reflects the following:


	•	The internal reorganization of Entergy’s corporate structure by means of transfers of equity interests of certain of its subsidiaries so that we hold substantially all of the assets of the non-utility nuclear business.
	•	Entergy’s transfer to us of $1.0 billion in cash as a capital contribution.
	•	Entergy’s transfer to us of $1.0 billion of loans payable to associated companies, net of loans receivable from associated companies.
	•	The issuance of and transfer by us to Entergy of $3.0 billion of debt securities at an annual interest rate of approximately 8%, which is the rate that Entergy charged us for loans payable at December 31, 2007, along with $37.5 million of debt issuance costs that will be deferred and amortized over the life of the debt. Entergy has informed us that, shortly after the separation, it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any cash proceeds from the portion of our debt securities that are transferred to Entergy.

(2) Reflects the following:


	•	The issuance by us of $1.5 billion of debt securities at an annual interest rate of approximately 8%, which is the rate that Entergy charged us for loans payable at December 31, 2007, along with $18.75 million of debt issuance costs that will be deferred and amortized over the life of the debt.
	•	The repayment by us of a net amount of $2.2 billion of loans payable to associated companies along with interest that had accrued thereon.

A nominal change of .125% in the interest rate used in (1) and (2) would result in a corresponding $5.6 million change in the pro forma interest expense for (1) and (2).

(3) Reflects the following:


	•	The adjustment to the net operating loss carryforward for amounts allocated to us pursuant to Entergy’s consolidated tax sharing agreement to the amount of net operating loss carryforward that we will be allocated under the U.S. Treasury regulations at the separation.
	•	The net effects of the assumption of our FIN 48 liabilities by Entergy for items for which Entergy is the primary obligor for tax-related issues existing prior to the separation.

(4) Reflects the following:


	•	The replacement of the $1.9 billion of guarantees of our performance or obligations that Entergy Corporation or its wholly-owned subsidiaries have issued. Fees charged to us by Entergy for these guarantees are included in “Interest expense to associated companies” on the income statement.
	•	Interest on the letters of credit, drawn on our credit facility, that are expected to replace some of the Entergy Corporation guarantees, at a rate of 4.5%, which is the rate that Entergy charged us for letters of credit at December 31, 2007. A nominal change of .125% in the interest rate used for the letters of credit would result in a corresponding $0.8 million change in the pro forma interest expense for (4).

(5) Reflects Entergy’s minority interest in the earnings of EquaGen because, under the applicable accounting rules, we expect that we will have control of EquaGen for financial reporting purposes, and therefore will consolidate EquaGen in our financial statements. If the terms of EquaGen’s agreement with us had been in effect in 2007, EquaGen would have earned $58 million in income before income taxes under the agreement. Entergy’s minority interest in EquaGen on our pro forma balance sheet as of December 31, 2007 is insignificant.

(6) Basic and diluted net income per share is calculated by dividing net income by 196,572,945 shares, which is the average number of shares of Enexus Energy’s common stock that would have been outstanding for 2007, based on an assumed distribution ratio of one Enexus Energy share of common stock for each Entergy share of common stock outstanding.

Taxes were provided for at an estimated statutory rate of 36.5%.

After the effect of the pro forma transactions, we would have an incremental increase in our cash and cash equivalents of $366 million. Because of the uncertainty regarding the uses, and the timing of the uses, of those funds, we have not provided a pro forma entry for the potential increase in interest income as a result of the pro forma transactions.

The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement.

We expect that the costs we will incur as a stand-alone company will initially include payment for services we expect to be provided by Entergy under a transition services agreement, which will become effective immediately after the consummation of the spin-off. Under the transition services agreement, Entergy will continue to provide, for a period to be determined, certain services that it has historically provided to us. During the period of the transition services agreement, we will incur one-time costs for transition activities and may incur some duplicative expenses as we start up certain stand-alone functions. Following the full implementation of our stand-alone functions and the termination of the transition services agreement, we expect costs for the stand-alone services to be similar to or slightly higher than our historical costs.

SELECTED HISTORICAL COMBINED FINANCIAL DATA

The following table sets forth our selected historical combined financial data as of and for each of the periods indicated. We derived the selected historical combined financial data as of and for each of the five years ended December 31, 2007 from our combined financial statements. The combined income statement data included herein for the years ended December 31, 2005, 2006, and 2007, and the combined balance sheet data as of December 31, 2006 and 2007 included herein is derived from our audited financial statements included elsewhere in this information statement. The combined income statement data for the years ended December 31, 2003 and 2004, and the combined balance sheet data as of December 31, 2003, 2004 and 2005 included herein is derived from our unaudited financial statements, which are not included in this information statement. This information is only a summary and you should read it in conjunction with the historical combined financial statements and the related notes and “Management’s Discussion and Analysis of Results of Operations and Financial Condition,” included elsewhere in this information statement. This information should also be read in conjunction with our unaudited pro forma condensed combined financial information. Our selected historical combined financial data are not necessarily indicative of our future results of operations, cash flows and financial position, and does not reflect what our results of operations, cash flows and financial position would have been as a stand-alone company for the periods presented.


	2007⁽¹⁾		2006		2005		2004		2003
	(In Thousands)

Operating revenues	$	2,029,666	$	1,544,873	$	1,421,547	$	1,341,852	$	1,274,983
Operating expenses		1,315,550		1,054,010		980,491		959,037		1,045,966
Operating income		714,116		490,863		441,056		382,815		229,017
Interest and dividend income		102,842		83,161		66,840		63,571		36,785
Interest expense		118,172		108,488		90,706		81,669		89,227
Income before cumulative effect of accounting change⁽²⁾		486,048		276,791		255,358		232,352		112,806
Net income		486,048		276,791		255,358		232,352		267,306

Total assets		7,018,119		5,352,054		4,999,953		4,810,400		4,407,576
Loans payable - affiliates		1,256,627		868,815		927,775		934,101		964,375
Long-term debt (excludes current maturities)		210,732		237,553		292,682		368,328		440,663

⁽¹⁾ Includes the effects of acquiring the Palisades power plant in April 2007.

⁽²⁾ Effective January 1, 2003, Entergy Nuclear Holding adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” and recorded a cumulative effect of a change in accounting principle in 2003.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Overview

In November 2007, Entergy’s Board of Directors approved a plan to pursue a separation of Entergy’s Non-Utility Nuclear business from Entergy through a tax-free spin-off of the business to Entergy shareholders. We were incorporated to effect the separation, and currently are a wholly owned subsidiary of Entergy. We will have no material assets or activities as a separate corporate entity until the contribution to us by Entergy, prior to the completion of the spin-off, of the business described in this information statement. Entergy conducts this business through various subsidiaries that primarily comprise its Non-Utility Nuclear business segment. Upon completion of the spin-off, Entergy Corporation’s shareholders will own 100% of our common equity. Our capital structure will change significantly on the date of the spin-off from Entergy.

Our business primarily consists of owning and operating six nuclear power plants and selling the electric power produced by those plants primarily to wholesale customers. Five of our power plants are located in the Northeast United States and the sixth is located in Michigan. Our power plants have nearly 5,000 megawatts of nuclear generating capacity, and we produced 37,570 gigawatts of electricity and $2.0 billion of revenue in 2007. We also provide plant operation support services for the Cooper Nuclear Station in Nebraska, which is owned by a third party.

In connection with the separation we expect to contribute our nuclear services business, which is also currently part of Entergy’s Non-Utility Nuclear segment, to a joint venture with Entergy, with 50% ownership by us and 50% ownership by Entergy (EquaGen). The nuclear services business operates our nuclear assets. The nuclear services business also offers nuclear services to third parties, including decommissioning, plant relicensing, and plant operation support services. The nuclear services business contributed less than 1% of our net income and revenues in 2007. Under the applicable accounting rules, we expect that we will have control of EquaGen for financial reporting purposes, and therefore will consolidate EquaGen in our financial statements.

Before our separation from Entergy, we will enter into various agreements with Entergy or EquaGen to effect the separation and provide a framework for our relationships with Entergy, Entergy’s other businesses, and EquaGen after the separation. These agreements will govern the relationships among us, EquaGen, Entergy and Entergy’s other businesses subsequent to the completion of the separation and provide for the allocation among us, EquaGen, Entergy and Entergy’s other businesses, of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the Non-Utility Nuclear business attributable to periods prior to, at and after our separation from Entergy.

Basis of Presentation

We have historically operated as the non-utility nuclear business of Entergy and not as a stand-alone company. The combined financial statements presented herein are comprised of entities included in the consolidated financial statements and accounting records of Entergy that principally represent its Non-Utility Nuclear segment, using the historical results of operations and the historical basis of assets and liabilities of the business. The combined statements of operations include expense allocations for certain corporate functions historically provided to us by Entergy, including general corporate expenses and employee benefits and incentives. These allocations were made on a specifically identifiable basis or using relative percentages, as compared to Entergy’s other businesses, of various factors. We believe that these cost allocations are reasonable for the services provided.

We believe the assumptions underlying the combined financial statements are reasonable. The historical and pro forma combined financial information included in this information statement, however, does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a

separate, publicly-traded company during the periods presented or those that we will achieve in the future primarily as a result of the following factors:


	•	Prior to our separation, our business was operated by Entergy as part of its broader corporate organization, rather than as a separate, publicly-traded company. Entergy or one of its affiliates performed various corporate functions for us, including, but not limited to, accounts payable, cash management, treasury, tax administration, legal, regulatory, certain governance functions (including compliance with the Sarbanes-Oxley Act of 2002 and internal audit) and external reporting. Our historical and pro forma financial results reflect allocations of corporate expenses from Entergy for these and similar functions. These allocations may differ from what those expenses would be had we operated as a separate, publicly-traded company.

	•	Currently, our business is integrated with the other businesses of Entergy. Historically, we have shared economies of scope and scale in costs, employees, vendor relationships and certain customer relationships. While we expect to enter into the Joint Venture Agreements and short-term transition agreements that will govern certain commercial and other relationships among us, Entergy, EquaGen and Entergy’s other businesses, those contractual arrangements may not capture the benefits our business has enjoyed as a result of being integrated with Entergy and its other businesses. The loss of these benefits of scope and scale may have an adverse effect on our business, results of operations and financial condition following the completion of the separation.

	•	Subsequent to the completion of our separation, the borrowing costs for our business may be higher than the borrowing costs that Entergy charged to us prior to our separation.

Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operating as a company separate from Entergy.

Entergy grants stock options to key employees of Entergy and its subsidiaries under its Equity Ownership Plan, which is a shareholder-approved stock-based compensation plan. The Equity Ownership Plan includes provisions whereby the Personnel Committee of the Entergy board of directors can act, in the event of a corporate event such as a spin-off that potentially dilutes the value of the underlying stock of Entergy stock options held by employees, to preserve the current intrinsic value of the stock option awards. Potential actions by the Personnel Committee could be to adjust the exercise price of the option and adjust the number of Entergy options held by employees or grant options in our stock, or a combination of both, to prevent dilution in the total value of the options held by employees. If such action is taken and the Entergy Equity Ownership Plan is considered modified under the applicable accounting rules, Entergy may be required to recognize incremental compensation cost for the difference in the fair market value of the outstanding equity awards before and after any adjustment by the Entergy board, which could be significant. The change in fair value would be recognized immediately for vested awards and over the vesting period for unvested awards. The weighted average remaining vesting period for all unvested Entergy stock options is 1.8 years as of December 31, 2007. We would be allocated a portion of this charge for our projected employees. The amount of such a charge, if required, would be based upon a number of factors that are not yet known, including, but not limited to, our actual employees, the number of shares that will be outstanding before and after any adjustment by the Entergy board, the expected value of Entergy and our equity at or near the spin-off date, and the expected volatilities of Entergy stock, our stock, or both. Although the ultimate decision of the Personnel Committee, the factors noted above, and their required accounting are not yet known, the amount of

expense that we could record in the future based upon outstanding equity awards and assumptions at December 31, 2007 could be material.

Acquisition of the Palisades Power Plant

In April 2007, we purchased the 798 MW Palisades nuclear energy plant located near South Haven, Michigan from Consumers Energy Company for a net cash payment of $336 million. We received the plant, nuclear fuel, inventories, and other assets. The liability to decommission the plant, as well as related decommissioning trust funds, was also transferred to us. We executed a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. In the first quarter 2007, the NRC renewed Palisades’ operating license until 2031. Also as part of the transaction, we assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Palisades’ financial results since April 2007 are included in our financial statements. See Note 10 to the financial statements herein for a discussion of the purchase price allocation and the amortization to revenue of the below-market PPA.

Results of Operations

2007 Compared to 2006

Net income for 2007 increased $209 million, or 76%, as compared to 2006, primarily due to the reasons described below.

Net Revenue (operating revenues less fuel and fuel-related expenses)

As a wholesale generator, our core business is selling energy, measured in MWh, to our customers, which is the principal source of our operating revenues. We achieve this by entering into forward contracts with our customers and selling energy in the day ahead or spot markets. In addition to selling the energy produced by our plants, we sell unforced capacity to load-serving entities, which allows those companies to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Our forward fixed price power contracts consist of contracts to sell energy only, contracts to sell capacity only and bundled contracts in which we sell both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires us to deliver MWh of energy to our counterparties, make capacity available to them, or both.

Net revenue increased by $457 million, or 33%, in 2007 primarily due to higher pricing in our contracts to sell power and additional production available resulting from the acquisition of Palisades in April 2007. We sold 4,051 gigawatt hours of generation from the Palisades plant in 2007, and it contributed $189 million of net revenue. Included in the Palisades net revenue is $50 million of amortization of the Palisades purchased power agreement liability, which is discussed in Note 10 to the financial statements. The

increase was partially offset by the effect on revenues of four refueling outages in 2007 compared to two in 2006. Following are key performance measures for 2007 and 2006:


	2007		2006

Net MW in operation at December 31		4,998		4,200
Average realized price per MWh		$52.69		$44.33
GWh billed		37,570		34,847
Capacity factor		89%		95%
Refueling outage days:
FitzPatrick		-		27
Indian Point 2		-		31
Indian Point 3		24		-
Palisades		42		-
Pilgrim		33		-
Vermont Yankee		24		-

The majority of the existing long-term contracts on our five Northeast power plants expire by the end of 2012. Most of the existing contracts have contract prices that are lower than currently prevailing market prices. See “Market and Credit Risks” for additional information regarding our current contracts to sell power.

We analyze revenues net of fuel and fuel-related expenses because those expenses are relatively stable as a percentage of power generated. We capitalize nuclear fuel when it is purchased and record it as part of property, plant, and equipment. We then amortize nuclear fuel and record expense using a units-of-production method as power is generated. The $27.8 million, or 20%, increase in fuel expense in 2007 is primarily due to the acquisition of Palisades in April 2007.

Other Income Statement Items

Other operation and maintenance expenses increased by $132 million, or 20%, primarily due to the acquisition of Palisades in April 2007, which contributed $90 million to other operation and maintenance expenses. Also contributing to the increase were expenses of $29 million ($18.4 million net-of-tax) in the fourth quarter 2007 in connection with the nuclear operations fleet alignment. This process was undertaken with the goals of eliminating redundancies, capturing economies of scale, and clearly establishing organizational governance. Most of the expenses related to the voluntary severance program offered to employees. Approximately 200 employees accepted the voluntary severance program offers.

We defer nuclear refueling outage costs during the refueling outages and amortize them over the estimated period to the next outage because these refueling outage costs are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Nuclear refueling outage costs increased $14 million, or 16%, primarily due to four refueling outages occurring in 2007 as opposed to two in 2006, and the costs of the more recent outages being higher than the previous refueling outages for those plants.

Depreciation and amortization increased by $28 million, or 38%, primarily as a result of the acquisition of Palisades in April 2007.

Decommissioning expense increased by $43 million primarily due to reduced expense of $27 million ($16.6 million net-of-tax) in 2006 resulting from a reduction in the decommissioning liability for a plant as a result of a revised decommissioning cost study and changes in assumptions regarding the timing of when decommissioning of a plant will begin. Decommissioning expense also increased as a result of the acquisition of Palisades in April 2007.

Taxes other than income taxes primarily consist of ad valorem and employment taxes. Taxes other than income taxes increased by $16 million, or 26%, primarily due to the acquisition of Palisades in April 2007.

We primarily earn interest and dividend income on our decommissioning trust funds, in addition to interest earned on temporary cash investments. Interest and dividend income increased by $20 million, or 24%, primarily due to higher interest earned on decommissioning trust funds.

Income Taxes

The effective income tax rate was 30.4% in 2007 and 40.5% in 2006. The reduction in the effective income tax rate in 2007 is primarily due to:


	•	a reduction in income tax expense due to a step-up in the tax basis on the Indian Point 2 non-qualified decommissioning trust fund resulting from restructuring of the trusts, which reduced deferred taxes on the trust fund and reduced current tax expense;

	•	the resolution of tax audit issues involving the 2002-2003 audit cycle; and

	•	an adjustment to state income taxes to reflect the effect of a change in the methodology of computing New York state income taxes as required by that state’s taxing authority.

See Note 2 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.

2006 Compared to 2005

Net income for 2006 increased $21 million, or 8%, as compared to 2005, primarily due to the reasons described below.

Net Revenue (operating revenues less fuel and fuel-related expenses)

Net revenue increased by $115 million, or 9%, in 2006 primarily due to higher pricing in our contracts to sell power. Also contributing to the increase in revenues was increased generation in 2006 due to power uprates completed in 2005 and 2006 at certain plants and fewer refueling outages in 2006. Following are key performance measures for 2006 and 2005:


	2006		2005

Net MW in operation at December 31		4,200		4,105
Average realized price per MWh		$44.33		$42.26
GWh billed		34,847		33,641
Capacity factor for the period		95%		93%
Refueling Outage Days:
FitzPatrick		27		-
Indian Point 2		31		-
Indian Point 3		-		26
Pilgrim		-		25
Vermont Yankee		-		20

Other Income Statement Items

Other operation and maintenance expenses increased by $38 million, or 6%, in 2006 primarily due to the timing of refueling outages, increased benefits and insurance costs, and increased NRC fees.

Depreciation and amortization increased by $13 million, or 23%, primarily as a result of an increase in plant in service.

Interest and dividend income increased by $16 million, or 24%, primarily due to higher interest earned on temporary cash investments and decommissioning trust funds.

Interest expense to associated companies increased by $19 million, or 26%, in 2006 primarily due to an increase in the average rate charged from 5.06% in 2005 to 7.20% in 2006.

Income Taxes

The effective income tax rate was 40.5% in 2006 and 38.6% in 2005. See Note 2 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.

Liquidity and Capital Resources

This section discusses our capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.

Capital Structure

Our debt to capital ratio, on a historical and pro forma basis, is shown in the following table. Pro forma debt to capital is significantly higher than the historical ratios because we plan to issue $4.5 billion in debt and expect to have negative equity as a result of the separation.


	Pro forma		Historical
	2007		2007		2006

Net debt to net capital at the end of the year		120.4%		31.7%		29.5%
Effect of subtracting cash from debt		(4.0%)		7.7%		8.6%

Debt to capital at the end of the year		116.4%		39.4%		38.1%

Net debt consists of debt less cash and cash equivalents. Debt consists of loans payable—associated companies and long-term debt, including the currently maturing portion. Capital consists of debt and shareholders’ equity. Net capital consists of capital less cash and cash equivalents. We use the net debt to net capital ratio in analyzing our financial condition and believe it provides useful information to investors and creditors in evaluating our financial condition.

Summary of Contractual Obligations


Contractual Obligations	2008		2009-2010		2011-2012		after 2012		Total
	(In thousands)

Loans payable - associated companies (1)		$1,256,627		$-		$-		$-		$1,256,627
Long-term debt (2)		35,752		71,867		67,292		160,343		335,254
Operating leases (3)		4,968		8,465		5,302		3,912		22,647
Purchase obligations (4)		150,201		395,787		277,935		180,402		1,004,325

Total	$	1,447,548	$	476,119	$	350,529	$	344,657	$	2,618,853


(1)		Loans payable -associated companies are due on demand, and as discussed further below we expect to repay them as part of the separation. Contractual obligation amount does not include estimated interest payments because we plan to repay them as part of the separation. Interest on these loans payable as of December 31, 2007 was 7.98%. Loans payable - associated companies are discussed in Note 3 to the financial statements.
(2)		Includes estimated interest payments. Long-term debt is discussed in Note 3 to the financial statements.
(3)		Operating lease obligations are discussed in Note 6 to the financial statements.
(4)		Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are for fuel purchase obligations.

In addition to the contractual obligations included in the table above, in 2008, we expect to contribute $44 million to pension plans and $3.4 million to other postretirement plans. Guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, may affect the level of our pension contributions in the future. Also in addition to the contractual obligations listed above, we have $774.7 million of unrecognized tax benefits and interest for which the timing of payments cannot be reasonably estimated due

to uncertainties in the timing of effective settlement of tax positions. See Note 2 to the financial statements for additional information regarding unrecognized tax benefits and see “Tax Sharing Agreement—Post-Separation” for a discussion of the effect of the separation on them.

We do not have any off-balance sheet arrangements.

Tax Sharing Agreement - Post-Separation

We and Entergy will enter into a Tax Sharing Agreement in connection with the separation transaction. The Tax Sharing Agreement will include provisions whereby Entergy is solely responsible for the Entergy consolidated federal income tax liability for periods prior to the effective date of the separation (“pre-spin”). However, we will be liable to Entergy in the situations described below.

Net operating loss carry-forwards

We will be allocated our share of the Entergy consolidated net operating loss carry-forward (CNOL) at the spin-off date. Our share of the Entergy CNOL is estimated to be $468.8 million as of December 31, 2007. The Entergy CNOL available for allocation between Entergy and us is based upon tax items of both our and other Entergy companies that were included in the pre-spin consolidated tax returns. To the extent that a tax item is successfully disallowed upon IRS audit of pre-spin tax years, it may reduce the allocable CNOL and, therefore, reduce the portion allocated to us. If our CNOL is used by us subsequent to the spin, but prior to the resolution of such audit, then we would have a cash obligation to the IRS for the post-spin use of our CNOL that was generated by the disallowed items plus interest. For our tax items giving rise to the CNOL that are timing differences, we would reap the future cash benefit of that deduction, so there would be no net effect on our earnings other than interest expense. Our CNOL could also decrease, however, due to a successful challenge by the IRS of tax items claimed by various Entergy subsidiaries that will continue to be owned by Entergy post-spin. In this situation, should the disallowance exceed the FIN 48 liability for that item, then there would be a reduction in the deferred tax asset recorded for our share of the CNOL, which would reduce our earnings. (FIN 48 liability means any liability for an uncertain tax position recorded pursuant to FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes). Utilization of the Entergy CNOL between December 31, 2007 and the effective date of the separation will reduce our share of the Entergy consolidated CNOL. Should our post-separation share of the Entergy CNOL increase due to Entergy’s favorable resolution of tax audits, we will pay Entergy for the tax effect of such increase. We do not expect to owe Entergy any amount for increases to our post-separation share of the Entergy CNOL.

Uncertain tax positions

Entergy will retain the FIN 48 liability in its financial statements for pre-spin consolidated federal tax return items, because it is presumed to be the primary obligor for the Entergy consolidated federal income tax liability for pre-spin years. Entergy Nuclear Power Marketing, LLC will retain its FIN 48 liability for the years that Entergy Nuclear Power Marketing, LLC was not a member of the Entergy consolidated federal income tax return. We will retain the FIN 48 liability for pre-spin state income tax return items for those states where it is presumed that we will be the primary obligor. Pursuant to the Tax Sharing Agreement, to the extent that Entergy owes the IRS an amount in excess of its FIN 48 liability for pre-spin items, we may be required to reimburse Entergy for the excess. Our potential liability to Entergy under this provision is not expected to exceed $120 million. For timing differences, any payment by us would be offset by the ability to claim that deduction in a future period and there would be no net effect on our earnings.

If any of our assets were the subject of a transaction in which capital gain was recognized by Entergy or us in a pre-spin tax year and that gain was offset by a pre-spin capital loss, then we may owe Entergy if a portion of the pre-spin capital loss is disallowed by the IRS. Any payments under the preceding sentence will reduce our earnings. The potential impact of the capital loss tax sharing is not expected to be material to our financial position or results of operations as of December 31, 2007.

Deferred Taxes

Our deferred tax assets and deferred tax liabilities associated with pre-spin tax deductions reflect only that portion of our deductions that met the more-likely-than-not standard under FIN 48. Our effective tax rate may be increased in future periods, because the FIN 48 liability related to these items will be recorded at Entergy, while only the certain portion of these deferred tax assets and liabilities will be turned around to earnings each period in our financial statements. Over time, this increase to our effective tax rate will reverse.

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of our planned construction and other capital investments for 2008 through 2010:


Planned construction and capital investments	2008		2009		2010
	(In Millions)

Capital Commitments	$	207	$	117	$	176
Maintenance Capital		78		78		78

Total	$	285	$	195	$	254

Maintenance Capital refers to amounts we plan to spend on routine capital projects that are necessary to support safety and reliability of service, equipment, or systems.

Capital Commitments refers to non-routine capital investments for which we are either contractually obligated, have Entergy board approval, or otherwise expect to make to satisfy regulatory or legal requirements. Amounts reflected in this category include dry cask spent fuel storage and license renewal projects at certain nuclear sites, and NYPA value sharing costs for 2008. Estimated capital expenditures are subject to periodic review, study, and modification and may vary based on the ongoing effects of operations, business restructuring, regulatory constraints and requirements, including environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.

Power sale collateral requirements

Some of the agreements to sell the power produced by our power plants contain provisions that require an Entergy subsidiary to provide collateral to secure our obligations under the agreements. The Entergy subsidiary will be required to provide collateral based upon the difference between the current market and contracted power prices in the regions where we sell power. The primary form of collateral to satisfy these requirements would be an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2007, based on power prices at that time, Entergy had in place as collateral $702 million of Entergy Corporation guarantees for wholesale transactions, including $63 million of guarantees that support letters of credit. The assurance requirement is estimated to increase by an amount up to $294 million if gas prices increase $1 per MMBtu in both the short- and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, Entergy will be required to replace Entergy Corporation guarantees with cash or letters of credit under some of the agreements.

In connection with the separation, we expect to replace these Entergy guarantees related to power sale collateral requirements with a combination of letters of credit, cash, guarantees issued by us, or liens on our property.

Dividends

Currently, we do not anticipate paying a regular dividend. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors.

Sources of Capital

Historically, our sources to meet our capital requirements and fund investments included:


	•	internally generated funds;
	•	cash and cash equivalents ($428.9 million as of December 31, 2007);
	•	loans and capital contributions from Entergy and its subsidiaries; and
	•	seller financing.

Circumstances such as power and fuel price fluctuations, and unanticipated expenses, including unscheduled plant outages, could affect the timing and level of internally generated funds in the future. Our cash flow activity for the previous three years is discussed below.

Subsequent to the spin-off transaction, Entergy will not provide us with capital to finance our capital requirements. As discussed further below, we will obtain capital from other sources. We will have a credit rating that is lower than Entergy’s credit rating and, as a result, will incur debt on terms and at interest rates that will not be as favorable as those available to Entergy.

New Financing Arrangements

We currently expect that in connection with the separation, we will incur up to $4.5 billion of debt in the form of publicly or privately issued debt securities. We expect to transfer to Entergy up to approximately $4.0 billion in the form of either cash proceeds from the issuance of debt securities or a portion of such debt securities, or both, in partial consideration for Entergy’s transfer to us of the non-utility nuclear business and in repayment of both the loans payable to associated companies that are currently on our balance sheet and also transferred to us as part of the spin-off transaction. There will be no outstanding debt between Entergy and us immediately following the spin-off. Entergy has informed us that, shortly after the separation, it expects to use our debt securities it has received to reduce or retire Entergy debt by exchanging our debt with certain holders of Entergy Corporation debt. We will not receive any cash proceeds from the portion of our debt securities that are transferred to Entergy. The amount to be paid to Entergy, the amount and term of the debt we will incur, and the type of debt and entity that will incur the debt have not been finally determined, but will be determined prior to the separation. A number of factors could affect this final determination, and the amount of debt ultimately incurred could be different from the amount disclosed in this information statement. Additionally, we intend to enter into one or more credit facilities or other financing arrangements meant to support our working capital needs and collateral obligations arising from hedging and normal course of business requirements.

We expect regulatory restrictions and the terms of our indebtedness will limit our ability to raise capital through our subsidiaries, pledge the stock of our subsidiaries, encumber the assets of our subsidiaries and cause our subsidiaries to guarantee our indebtedness.

We expect cash and cash equivalents on hand, cash flows from operations, and borrowings under our planned credit facilities to satisfy working capital, capital expenditure and debt service requirements in 2008, and for at least the succeeding year after the separation.

Cash Flow Activity

As shown in our Statements of Cash Flows, cash flows for the years ended December 31, 2007, 2006, and 2005 were as follows:


	2007			2006			2005
	(In Millions)

Cash and cash equivalents at beginning of period		$384			$212			$140

Cash flow provided by (used in):
Operating activities		838			808			560
Investing activities		(883	)		(450	)		(368	)
Financing activities		90			(186	)		(120	)

Net increase in cash and cash equivalents		45			172			72

Cash and cash equivalents at end of period		$429			$384			$212

Operating Activities

2007 Compared to 2006

Our cash flow provided by operating activities increased by $30 million in 2007 compared to 2006 primarily due to higher net revenue and a decrease of $24 million in the amount of pension funding payments made in 2007. This was almost entirely offset by the receipt of income tax refunds in 2006, compared to income tax payments being made in 2007, and the spending associated with four refueling outages in 2007 compared to two in 2006.

2006 Compared to 2005

Our cash flow provided by operating activities increased by $248 million in 2006 compared to 2005 primarily due to higher net revenue and the receipt of an income tax refund. Entergy Corporation received an income tax refund as a result of net operating loss carryback provisions contained in the Gulf Opportunity Zone Act of 2005. In accordance with Entergy’s intercompany tax allocation agreement, $71 million of the refund was distributed to our business in 2006.

Investing Activities

2007 Compared to 2006

Net cash used in investing activities increased by $433 million in 2007 compared to 2006 primarily due to the $336 million purchase of the Palisades power plant in April 2007. Also, primarily because of the increase in refueling outages in 2007, we spent $126 million more on nuclear fuel purchases in 2007. These increases were partially offset by a $43 million decrease in construction expenditures.

2006 Compared to 2005

Net cash used in investing activities increased $82 million in 2006 compared to 2005 primarily due to a $142 million increase in construction expenditures in 2006, partially offset by a decrease of $65 million in nuclear fuel purchases due to two refueling outages in 2006 compared to three refueling outages in 2005.

Financing Activities

2007 Compared to 2006

Net cash provided by financing activities was $90 million in 2007 compared to net cash flow used in financing activities of $186 million in 2006 primarily due to the $350 million in debt proceeds received to

finance the purchase of the Palisades power plant in April 2007, partially offset by fluctuations in intercompany financing activity with Entergy and its subsidiaries.

2006 Compared to 2005

Net cash used in financing activities increased $66 million in 2006 compared to 2005 primarily due to fluctuations in intercompany financing activity with Entergy and its subsidiaries.

Market and Credit Risk

Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating results or cash flows, in response to changing market conditions. We hold commodity and financial instruments that are exposed to the following significant market risks:


	•	The commodity price risk associated with the sale of electricity.
	•	The interest rate and equity price risk associated with our investments in decommissioning trust funds. See Note 12 to the financial statements for details regarding our decommissioning trust funds.
	•	The interest rate risk associated with changes in interest rates as a result of our loans payable and long-term debt outstanding. See Note 3 to the financial statements for the details of our loans payable - associated companies and long-term debt outstanding.

Our commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Credit risk also includes potential demand on liquidity due to collateral requirements within supply or sales agreements.

Commodity Price Risk

Power Generation

As a wholesale generator, our core business is selling energy, measured in MWh, to our customers. We achieve this by entering into forward contracts with our customers and selling energy in the day ahead or spot markets. In addition to selling the energy produced by our plants, we sell unforced capacity to load-serving entities, which allows those companies to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Our forward fixed price power contracts consist of contracts to sell energy only, contracts to sell capacity only and bundled contracts in which we sell both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires us to deliver MWh of energy to our counterparties, make capacity available to them, or both. See Note 11 to the financial statements for additional discussion of our risk management and hedging activity. The following is a summary as of December 31, 2007 of the amount of our nuclear power plants’ planned energy output that is currently sold forward:


	2008		2009		2010		2011		2012

Contracted Sale of Energy:
Percent of planned energy output sold forward:
Unit-contingent(1)		51%		48%		31%		29%		16%
Unit-contingent with guarantee of availability(2)		36%		35%		28%		14%		7%
Firm liquidated damages(3)		5%		0%		0%		0%		0%

Total		92%		83%		59%		43%		23%
Planned energy output (TWh)		41		41		40		41		41
Average contracted price per MWh(4)		$54		$61		$58		$55		$51


(1)		A unit-contingent transaction is one where power is supplied from a specific generation asset; if the asset is unavailable, the seller is not liable to the buyer for any damages.


(2)		A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event we, the seller, fail to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of our outstanding guarantees of availability provide for dollar limits on our maximum liability under such guarantees.

(3)		A firm liquidated damages transaction requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific generation asset); if a party fails to deliver or receive energy, the defaulting party must pay a liquidated damages amount to the other party, as specified in the contract.

(4)		The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy most of the power produced by the plant through the expiration of the current operating license for the plant in 2012. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below the PPA prices.

The following is a summary of the amount of our business’ installed capacity that is currently sold forward, and the blended amount of our business’ planned energy output and installed capacity that is, as of December 31, 2007, currently sold forward:


	2008		2009		2010		2011		2012

Contracted Sale of Capacity:
Percent of capacity sold forward:
Bundled capacity and energy contracts		27%		26%		26%		26%		19%
Capacity contracts		59%		34%		16%		9%		2%

Total		86%		60%		42%		35%		21%
Planned net MW in operation		4,998		4,998		4,998		4,998		4,998
Average capacity contract price per kW per month		$1.8		$1.7		$2.5		$3.1		$3.5

Blended energy and capacity (based on revenues):
% of planned energy and capacity sold forward		89%		79%		51%		35%		17%
Average contract revenue per MWh		$56		$62		$59		$56		$52

Entergy’s Non-Utility Nuclear business’ purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Entergy and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Entergy’s Non-Utility Nuclear business agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy’s Non-Utility Nuclear business will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year is due by January 15 of the following year, with the payment for year 2007 output due on January 15, 2008. If Entergy or an Entergy affiliate ceases to own the plants, then, after January 2009, the annual payment obligation terminates for generation after the date that Entergy ownership ceases. Therefore, after the spin-off transaction, we do not expect to make value sharing payments to NYPA, other than for 2008 generation, assuming the spin-off transaction is completed as expected in 2008.

We will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. We recorded a $72 million liability for generation through December 31, 2007. An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.

Our purchase of the Vermont Yankee plant included a value sharing agreement providing for payments to the seller in the event that the plant’s operating license is extended beyond its original expiration in 2012. Under the value sharing agreement, to the extent that the average annual price of the energy sales from the

plant exceeds the specified strike price, initially $61/MWh, and then adjusted annually based on three indices, we will pay half of the amount exceeding the strike prices to the seller. We expect that these payments, if required, will be recorded as adjustments to the purchase price of Vermont Yankee. The value sharing would begin in 2012 and extend into 2022.

Critical Accounting Estimates

The preparation of our financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of our financial position or results of operations.

Nuclear Decommissioning Costs

We own six nuclear generation facilities and one shutdown nuclear generating facility. Regulations require us to decommission our nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. We conduct periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates:


	•	Cost Escalation Factors - Our decommissioning revenue requirement studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from approximately CPI-U to 5.5%. A 50 basis point change in this assumption could change the ultimate cost of decommissioning a facility by as much as 11%.
	•	Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. The expiration of the plant’s operating license is typically used for this purpose, but the assumption may be made that the plant’s license will be renewed and operate for some time beyond the original license term. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in “safestore” status for later decommissioning, as permitted by applicable regulations. While the effect of these assumptions cannot be determined with precision, assuming either license renewal or use of a “safestore” status can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will affect net income to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized and depreciated over the asset’s remaining economic life in accordance with SFAS 143.
	•	Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. Until this site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities can have a significant effect (as much as 16% of estimated decommissioning costs). Our decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of the Yucca Mountain facility, the schedule for shipments to that facility when it is opened, or other factors.
	•	Technology and Regulation - To date, there is limited practical experience in the United States with actual decommissioning of large nuclear facilities. As experience is gained and technology changes, cost estimates could also change. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential


		changes is not presently determinable. Our decommissioning cost studies assume current technologies and regulations.

In the fourth quarter of 2007, we recorded an increase of $100 million in decommissioning liabilities for certain of our plants as a result of revised decommissioning cost studies. The revised estimates resulted in the recognition of a $100 million asset retirement obligation asset that will be depreciated over the remaining life of the units.

In the third quarter of 2006, we recorded a reduction of $27 million in decommissioning liability for a plant as a result of a revised decommissioning cost study and changes in assumptions regarding the timing of when decommissioning of the plant will begin. The revised estimate resulted in reduced expenses of $27 million ($16.6 million net-of-tax), reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143.

In the first quarter of 2005, we recorded a reduction of $26.0 million in decommissioning cost liability in conjunction with a new decommissioning cost study as a result of revised decommissioning costs and changes in assumptions regarding the timing of the decommissioning of a plant. The revised estimate resulted in reduced expenses of $26.0 million ($15.8 million net-of-tax), reflecting the excess of the reduction in the liability over the amount of undepreciated assets retirement cost recorded at the time of adoption of SFAS 143.

Qualified Pension and Other Postretirement Benefits

We participate in Entergy-sponsored qualified, defined benefit pension plans which cover substantially all employees. Additionally, we currently provide postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for us. Our reported costs of providing these benefits, as described in Note 7 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, our estimate of these costs is a critical accounting estimate for us.

Assumptions

Key actuarial assumptions utilized in determining these costs include:


	•	Discount rates used in determining the future benefit obligations;
	•	Projected health care cost trend rates;
	•	Expected long-term rate of return on plan assets; and
	•	Rate of increase in future compensation levels.

We review these assumptions on an annual basis and adjust them as necessary. The falling interest rate environment and worse-than-expected performance of the financial equity markets in previous years have impacted funding and reported costs for these benefits. In addition, these trends have caused us to make a number of adjustments to our assumptions.

In selecting an assumed discount rate to calculate benefit obligations, we review market yields on high-quality corporate debt and match these rates with our projected stream of benefit payments. Based on recent market trends, we increased our discount rate used to calculate benefit obligations from 6.0% in 2006 to 6.50% in 2007. Our assumed discount rate used to calculate the 2005 benefit obligations was 5.90%. We review actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, the health care cost trend rate assumption used in calculating the December 31, 2007 accumulated postretirement benefit obligation was a 9% increase in health care costs in 2008 gradually decreasing each successive year, until it reaches a 4.75% annual increase in health care costs in 2013 and beyond.

In determining its expected long-term rate of return on plan assets, we review past long-term performance, asset allocations, and long-term inflation assumptions. We target an asset allocation for our

pension plan assets of roughly 65% equity securities, 31% fixed-income securities and 4% other investments. The target allocation for our other postretirement benefit assets is 51% equity securities and 49% fixed-income securities. Our expected long-term rate of return on pension plan and non-taxable other postretirement assets used was 8.5% in 2007, 2006 and 2005. Our expected long-term rates of return on taxable other postretirement assets were 6% in 2007 and 5.5% in 2006 and 2005. The assumed rates of increase in future compensation levels used to calculate benefit obligations was 4.23% in 2007 and 3.25% in 2006 and 2005.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost to changes in certain actuarial assumptions (dollars in thousands):


				Impact on 2007		Impact on Qualified
	Change in			Qualified Pension		Projected
Actuarial Assumption	Assumption			Cost		Benefit Obligation
	Increase/(Decrease)

Discount rate		(0.25	%)	$	2,875	$	19,388
Rate of return on plan assets		(0.25	%)		$778		-
Rate of increase in compensation		0.25	%	$	1,887		$9,831

The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands):


					Impact on Accumulated
	Change in		Impact on 2007		Postretirement Benefit
Actuarial Assumption	Assumption		Postretirement Benefit Cost		Obligation
	Increase/(Decrease)

Health care cost trend		0.25%	$	1,573	$	6,514
Discount rate		(0.25%)	$	1,215	$	7,116

Each fluctuation above assumes that the other components of the calculation are held constant.

Accounting Mechanisms

In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” we utilize a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

Costs and Funding

In 2007, our total qualified pension cost was $36.8 million. We anticipate 2008 qualified pension cost to decrease to $30 million due to an increase in the discount rate (from 6.00% to 6.50%) and 2007 actual return on plan assets greater than 8.5%. We funded $36 million (including employee contributions of $1 million) to our pension funding in 2007. Our contributions to the pension trust are currently estimated to be $44 million (including employee contributions of $1 million) in 2008. Guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, may affect the level of our pension contributions in the future.

The Pension Protection Act of 2006 was signed by the President on August 17, 2006. The intent of the legislation is to require companies to fund 100% of their pension liability; and then for companies to fund, on a going-forward basis, an amount generally estimated to be the amount that the pension liability increases each year due to an additional year of service by the employees eligible for pension benefits. The legislation requires that funding shortfalls be eliminated by companies over a seven-year period, beginning in 2008. The Pension Protection Act also extended the provisions of the Pension Funding Equity Act that would have expired in 2006 had the Pension Protection Act not been enacted, which increased the allowed discount rate used to calculate the pension funding liability.

Total postretirement health care and life insurance benefit costs for us in 2007 were $16.2 million, including $4.4 million in savings due to the estimated effect of future Medicare Part D subsidies. We expect 2008 postretirement health care and life insurance benefit costs to be $15.2 million. This includes a projected $4.3 million in savings due to the estimated effect of future Medicare Part D subsidies. We expect to contribute $3.4 million in 2008 to our other postretirement plans’ costs.

Other Contingencies

We are subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which we operate that potentially subject us to environmental, litigation, and other risks. We periodically evaluate our exposure for such risks and record a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.

Environmental

We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Under these various laws and regulations, we could incur substantial costs to restore properties consistent with the various standards. We conduct studies to determine the extent of any required remediation and have recorded reserves based upon our evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites could be identified which require environmental remediation for which we could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:


	•	Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.
	•	The identification of additional sites or the filing of other complaints in which we may be asserted to be a potentially responsible party.
	•	The resolution or progression of existing matters through the court system or resolution by the EPA.

Litigation

We have been named as defendant in a number of lawsuits involving employment and injuries and damages issues, among other matters. We periodically review the cases in which we have been named as defendant and assess the likelihood of loss in each case as probable, reasonably estimable, or remote and record reserves for cases which have a probable likelihood of loss and can be estimated. The ultimate outcome of the litigation that we are exposed to has the potential to materially affect our results of operations.

New Accounting Pronouncements

In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 generally does not require any new fair value measurements. However, in some cases, the application of SFAS 157 in the future may change our practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. SFAS 157 is effective for us in the first quarter 2008 and will be applied

prospectively. Application of SFAS 157 did not materially affect our financial position, results of operations, or cash flows.

The FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) during the first quarter 2007. SFAS 159 provides an option for companies to select certain financial assets and liabilities to be accounted for at fair value with changes in the fair value of those assets or liabilities being reported through earnings. The intent of the standard is to mitigate volatility in reported earnings caused by the application of the more complicated fair value hedging accounting rules. Under SFAS 159, companies can select existing assets or liabilities for this fair value option concurrent with the effective date of January 1, 2008 for companies with fiscal years ending December 31 or can select future assets or liabilities as they are acquired or entered into. Adoption of this standard did not have a material effect on our financial position, results of operations, or cash flows.

The FASB issued Statement of Financial Accounting Standards No. 141(R), “Business Combinations” (SFAS 141(R)) during the fourth quarter 2007. The significant provisions of SFAS 141R are that: (i) assets, liabilities and non-controlling (minority) interests will be measured at fair value; (ii) costs associated with the acquisition such as transaction-related costs or restructuring costs will be separately recorded from the acquisition and expensed as incurred; (iii) any excess of fair value of the assets, liabilities and minority interests acquired over the fair value of the purchase price will be recognized as a bargain purchase and a gain recorded at the acquisition date; and (iv) contractual contingencies resulting in potential future assets or liabilities will be recorded at fair market value at the date of acquisition. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply SFAS 141(R) before that date.

The FASB issued Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Combined Financial Statements” (SFAS 160) during the fourth quarter 2007. SFAS 160 enhances disclosures surrounding minority interests in the balance sheet, income statement and statement of comprehensive income. SFAS 160 will also require a parent to record a gain or loss when a subsidiary in which it retains a minority interest is deconsolidated from the parent company. SFAS 160 applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply SFAS 160 before that date.

In April 2007 the FASB issued Staff Position No. 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 allows an entity to offset the fair value of a receivable or payable against the fair value of a derivative that is executed with the same counterparty under a master netting arrangement. This guidance becomes effective for fiscal years beginning after November 15, 2007. These provisions did not have a material effect on our financial position.

OUR INDUSTRY

Independent generating companies in the New England and New York markets, where five of our six nuclear power plants are located, operate on a competitive basis, with fundamental supply and demand driving the basis for power prices. We believe that those markets are characterized by a combination of demand growth, supply constraints, exposure to rising natural gas prices and exposure to potential carbon dioxide (CO₂) legislation. We believe that these trends, which we expect to continue into the future, were a factor in causing the New York and New England power markets to experience some of the highest average power prices in the United States in 2007. Palisades, our sixth plant, which operates in the Michigan market, also a competitive market, is currently fully contracted to Consumers Energy and therefore is unlikely to be materially affected by market fundamentals in the region until that contract expires in 2022.

Overview of Power Markets in the Northeast United States

ISO-NE and NYISO

In New England, where our Vermont Yankee and Pilgrim plants operate, the Independent System Operator New England (ISO-NE) is responsible for the day to day operation of New England’s bulk power and generation and transmission system. ISO-NE oversees and administers the region’s wholesale electricity markets and manages a comprehensive bulk power system planning process. The states that operate within the territory of the ISO-NE had, as of December 31, 2006, a total of approximately 6.5 million electricity customers, 350 generators, 8,000 miles of high voltage transmission lines, twelve interconnections with systems in New York and Canada and 31,000 MW of total supply. The New England market uses all regional generating resources to serve regional demand, independent of state boundaries.

In New York, where our Indian Point 2, Indian Point 3 and FitzPatrick plants operate, the New York Independent System Operator (NYISO) is responsible for managing the electricity transmission grid and overseeing and administering wholesale electric markets. As of November 2007, the region served by the NYISO had approximately 19.2 million electricity customers, 335 generators, a 10,775-mile network of high-voltage transmission lines and approximately 39,000 MW of total supply.

Day-Ahead and Real-Time Markets

In coordinating the sale and pricing of electricity in the Northeast, both the NYISO and the ISO-NE conduct day-ahead market and real-time market auctions. In the day-ahead market auction, generators submit offers of electricity supply and Load Serving Entities (LSEs), the entities which provide electric service to end-users, submit demand bids for electricity, one day ahead of actual dispatch (or actual use of the delivery and use of such electricity). These bids are applied to each hour of the day and for each pricing location. From these offers and bids, the ISO constructs aggregate supply and demand curves for each location. The intersection of these curves identifies the market-clearing price at each location for every hour. Supply offers below and demand bids above the identified price “clear,” or are scheduled. All scheduled generators receive the clearing marginal energy price. Offers and bids that clear are entered into a pricing software system along with binding transmission constraints to produce the prices for all locations, which are referred to as the locational marginal prices. The graph below illustrates how the market is cleared in the day-ahead market auction.

The quantities and prices that clear in the day-ahead market are financially, although not physically, binding. Generators and offers scheduled in the day-ahead settlement are paid the day-ahead locational marginal price for the MW accepted. Scheduled suppliers must produce the committed quantity during real-time or buy power from the real-time marketplace to replace what was not produced. Likewise, wholesale buyers of electricity whose bids to buy clear in the day-ahead market settlement pay for and lock in their right to consume the cleared quantity at the day-ahead locational marginal price. Electricity use in real-time that exceeds the day-ahead purchase is paid for at the real-time locational marginal price.

The real-time market is a spot market for energy. While the day-ahead market auction produces the schedule and financial terms of energy production and use for the operating day, a number of factors can change that schedule, including unforeseen generator or transmission outages, transmission constraints or changes from the expected demand. The real-time market addresses these deviations from the day-ahead settlement. Day-ahead locational marginal prices can differ from real-time locational marginal prices when supply offers or demand bids from the day-ahead are not identical to actual system supply or demand. This causes the real-time dispatch to deviate from the day-ahead financial commitment.

Market Pricing Dynamics

We believe that high natural gas prices, demand growth, supply constraints and potential CO₂ legislation have been factors in rising Northeast power prices and we expect these trends to continue into the future. As a result, we believe that our nuclear power plants, which have relatively low operating costs and virtually no CO₂ emissions, are well positioned to benefit from these market pricing dynamics.

Fuel Costs

The cost of fuel is the largest production cost variable for most electricity generators. In the day-ahead and real-time markets, market participants typically submit offers of electricity supply at prices that reflect their units’ marginal costs of production. The marginal unit is the plant that submits the highest accepted offer for electricity into the market at a point in time and is thus the unit that produces the last required MW of power to meet market demand. The marginal unit sets the market-clearing price of power in a region, which is the market price for every supplier. Therefore, as fuel costs of a marginal unit increase, the market-clearing price for power in the marketplace increases. Nuclear and solid fuel (such as coal) power plants have among the lowest fuel costs of all electricity suppliers, and therefore some of the lowest marginal production costs.

In the New England and New York markets, generating units that are capable of burning natural gas, fuel oil, or both, made up approximately 62% and 63%, respectively, of the electric generating capacity as of 2006. Because demand almost always exceeds supply available from nuclear and solid fuel power plants in these regions, the natural gas and fuel oil plants are usually the marginal plants that set the market-clearing price of wholesale power. As a result, the price of natural gas is one of the primary variables that affect the price of power in the Northeast.

Over the last several years, the price of natural gas has increased from an average of approximately $2.00/MMBtu throughout most of the 1990s to an average of almost $7.00/MMBtu in 2007. We believe that this increase in natural gas prices has been caused by a combination of factors, including increased demand for natural gas in the United States from electric generators, increased new construction of natural gas power plants since 1990, limited new construction of coal and nuclear power plants in the same period and an increased focus on and concern with greenhouse gas emissions from coal plants. We expect that the average natural gas prices reached over the last several years to stay at or higher than these levels, which we believe will contribute to higher power prices in the Northeast United States relative to the rest of the country.

Supply and Demand Characteristics

Demand Growth in ISO-NE and NYISO Markets

Both the New England and New York power grids are summer peaking systems, which means that the highest demand for power typically occurs during the summer season. Demand in the ISO-NE market reached an all-time high in the summer of 2006 with peak electricity use of 28,130 MW, surpassing the previous year’s peak by 1,245 MW. Similarly, the NYISO market reached peak summer demand levels of 33,939 MW in 2006. As illustrated in the chart below, the ISO-NE expects summer peak demand based on normalized weather assumptions to increase from 2008 to 2016 at a compound annual growth rate of 1.7%. The NYISO projects summer peak demand to increase during the same period at a compounded annual growth rate of 0.8%.

Source: “NYISO Comprehensive Reliability Planning Process March 2007;” “Results and Implications of the First Forward Capacity Market Auction ISO-NE April 2008”

Supply Constraints

In contrast to projected demand growth, siting, developing and constructing new generation plants in both the New York and New England markets is becoming increasingly difficult. We believe this is due to a combination of factors, including political pressures, uncertainty around greenhouse gas regulation initiatives and the increased incremental costs those initiatives will impose on newly constructed fossil fuel power plants, and the logistical challenges of construction of power plants in urban areas. In addition, siting in and around cities, the most capacity-constrained areas, is expensive, and planning and permitting can take years. Only 748 MW of capacity (representing approximately 2% of total capacity) were added in the ISO-NE region from 2004 to 2006, and no additional generation is under construction or expected to come online through 2010. In the NYISO region, approximately 4,575 MW of new generation was added from 2004 to 2006 in NYISO (representing approximately 12% of total capacity), but only 1,404 MW of new generation is under construction and expected to come online for the period from 2008 to 2010.

Shrinking Reserve Margins

As a result of expected rising peak load requirements and limited expected capacity additions, both the NYISO and ISO-NE project shrinking reserve margins. The reserve margin is a measure of available capacity over and above the capacity needed to meet the normal peak demand levels. The New York State Reliability Council designates a reserve margin of 15% for the NYISO, and the ISO-NE designates a reserve margin of 16%. Based on current generation capacity, ISO-NE expects reserve margins to fall below required levels in 2011, without additional demand response or capacity procured. NYISO expects reserve margins to fall below required levels by 2010 without additional capacity procured. The chart below illustrates the potential reserve margins as projected by ISO-NE and the NYISO through 2016 if new capacity is not added, as well as the respective reserve margin requirements for each region. The temporary increase in the reserve margin for 2010 in New England is due to the results of the Forward Capacity Auction #1 that was held in February 2008, which added 1,188 MW of capacity through demand response and 626 MW of capacity through new supply resources. The projected decrease in outer years in the ISO-NE reserve margin does not include additional capacity resulting from demand response planning.

Sources: “2007 NYISO Locational Minimum Installed Capacity Requirements Study” February 2008;” NYISO Comprehensive Reliability Planning Process” March 2007; “Results and Implications of the First Forward Capacity Market Auction” April 2008.

We expect the projected supply/demand dynamic to drive increasing market-clearing heat rates, and thus higher power prices, as increasing demand must be met with less efficient, higher heat rate capacity. Heat rate is a measurement used in the energy industry to calculate how efficiently an electric generator uses the heat energy in its fuel source to produce power. It is expressed as the number of BTUs of heat required to produce a kWh of energy. The marginal heat rate in any power market is defined as the heat rate of the plant that produces the marginal unit of energy at any given time. If the supply of power plants that have lower heat rates does not grow, then increased power demand must be met by less efficient power plants that have higher heat rates. We expect power prices to increase if these higher heat rate plants that have a higher marginal cost of production are forced to operate for longer periods of time to satisfy increasing demand. In the long term,

this incremental demand can be met by new capacity additions or by additional transmission. Coal and nuclear power plants, which typically have lower fuel prices and lower heat rates, are especially difficult to site and permit and require the longest lead times to construct. Therefore, we believe that most of the incremental demand in the Northeast market is likely to be met by higher heat rate gas capacity.

Capacity Markets

Each North American Electric Reliability Corporation (NERC) region in the United States is required by NERC’s electric reliability regulations to have sufficient generating capacity, as measured in total MW of generation available to provide energy to the region, to meet expected consumption of electricity. In many markets in the United States, a separate market for capacity does not exist, and the value of the underlying capacity is inherently included in the price of the energy generated. Due to current and forecasted shrinking reserve margins, over the past several years, both the NYISO and the ISO-NE have developed separate capacity markets in their respective regions to encourage investment in new generation and ensure system reliability. The capacity markets are essentially a mechanism for procuring capacity at market prices. In addition to the price that power plants in a capacity market receive for power sold, these plants are also eligible to receive payments related to the amount of their total capacity, in MW, that is uncontracted and available to provide power to the region. LSEs are required to purchase sufficient capacity to demonstrate their ability to provide electric energy in an amount equal to peak load forecast plus a reserve margin.

ISO-NE Capacity Market

In New England, the ISO-NE and regional stakeholders have been developing and negotiating a regional capacity market design since 2002. This multi-year endeavor culminated in March 2006 when numerous parties, including the ISO-NE, filed a settlement at FERC to establish a new forward capacity market (FCM), under which generating resources in the region receive payments for the amount of uncontracted capacity they have available to the region. As part of the development of the FCM, a transition payment mechanism was started on December 1, 2006, which provides fixed capacity payments to all existing capacity resources until FCM payments begin in June 2010. Following this transition period, FCM payments will be determined through an annual competitive auction process called a forward capacity auction (FCA). The ISO-NE will project the New England power system’s capacity requirements three years in advance and hold an FCA to purchase resources necessary to satisfy the region’s future needs. The first FCA for the June 1, 2010 through May 31, 2011 period was held in February 2008 and cleared at the floor price of $4.50/kW-month. However, because more capacity than the ISO-NE requested was cleared in the FCA, a pro-rated reduction of the $4.50 clearing price was made, based on the amount of excess capacity that cleared the auction. As a result of that reduction, the effective clearing price was $4.25/kW-month. The chart below illustrates capacity payments, in $/kW-month, that will be available for uncontracted capacity in ISO-NE through May 2011, based on the transitional FCM and as a result of the first FCA.

Source: ISO-NE website

NYISO Capacity Market

Generators in the NYISO region receive capacity payments through the installed capacity (ICAP) market. All LSEs in the region are required to procure sufficient capacity to meet specified reserve requirements. Through an auction process, market participants submit bids based on the amount of unforced capacity associated with their physical assets. Each year, suppliers are required to perform one test during the summer capability period and one test during the winter capability period to verify their maximum net capability. For example, if a generating unit with an installed capacity of 100 MWs undergoes a maximum net capability test, and the test results indicate that the unit can only produce 95 MWs, then the NYISO will rate this unit at 95 MWs for ICAP purposes. However, the ICAP market actually trades unforced capacity, which represents the amount of ICAP that is likely to be available at any given time. Unforced capacity is the percentage of ICAP available after a unit’s forced outage rate is calculated. The amount available for sale is established twice a year, once for the winter capability period and once for the summer capability period. A rolling 12 month average of the monthly forced outage rate is used to determine the amount of ICAP that can be sold in units of unforced capacity. For example, if the twelve month forced outage rate is 10%, the above “100 MW” unit would only be allowed to sell 85.5 MWs of unforced capacity in the next monthly ICAP auction. The unforced capacity product was developed with the intent of maintaining reliability in the New York marketplace by not only ensuring that capacity is available for current energy needs, but also providing incentives to improve the forced outage rates of existing generators.

Clearing prices for unforced capacity are set through three types of auctions in the NYISO: a winter and summer six month strip auction, with forward capacity for the full six month period; a monthly auction, with forward capacity for the remaining month in the period; and a spot auction, with prompt procurement of capacity.

Capacity prices in the New York Rest of State market (which includes all of New York State, with the exception of New York City), in which the Indian Point 2, Indian Point 3 and FitzPatrick plants participate, have increased considerably as demand has begun to outpace supply in the region. The chart below illustrates historical capacity prices in the New York Rest of State market from November 2004 through July 2007.

Source: NYISO

Pending CO₂ Legislation

There is increasing conviction in the scientific community and among U.S. political leaders that action must be taken to limit greenhouse gas emissions in order to mitigate global warming. CO₂ emission regulation is already in place in Europe, where CO₂ emissions allowances have been traded since 2005. U.S. state government officials have taken the lead on imposing domestic limits through proposals such as the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by ten states in the Northeast and Mid-Atlantic regions to reduce CO₂ emissions through a cap and trade program with a market-based emissions trading system. Under the proposal, state legislation would be enacted in 2009 with a 10% reduction in carbon emissions targeted by 2019.

We expect that over the next several years, some variation of a carbon tax or cap and trade program will be enacted via federal legislation. Both the U.S. Senate and House of Representatives are currently working to develop alternatives to address carbon emissions. Under a hypothetical carbon tax regime, the tax on greenhouse gas emissions would effectively be added to a power plant’s total operating cost. The largest emitters of greenhouse gases would therefore pay the highest tax, and because the operating costs of power plants determine the market price for power for all suppliers of power in a region, a carbon tax would effectively serve to increase the market price of power. We expect that for power plants that have virtually no greenhouse gas emissions, including nuclear power plants, a carbon tax would primarily manifest itself in the form of higher net revenue based on the increased market price for power.

Under a cap and trade system, regulators would establish a cap that would limit CO₂ emissions from a given power plant to a level lower than that plant’s current emissions level. The emissions allowed under the cap would be divided up into individual permits—usually equal to one ton of pollution—that represent the right to emit that amount. Because the emissions cap restricts the amount of pollution allowed, permits that give a company the right to pollute take on financial value and companies are free to buy and sell permits in order to continue operating in the most profitable manner available to them. Plants that continue to emit CO₂ at levels higher than their permits allow would have to purchase additional permits, whereas plants that are able to reduce emissions below the cap through investment in emission reduction technologies would have excess permits to sell to the market. We expect that, under a cap and trade system, the cost associated with reducing CO₂ emissions through investment or purchasing incremental permits will increase the marginal cost of production for carbon emitting power plants, thereby leading to increased power prices and, therefore, higher net revenue for power plants, such as nuclear power plants, that have virtually no CO₂ emissions.

Overview of Midwest Power Market

Our Palisades plant, which we purchased in April 2007, operates in the region of the United States that the Midwest Independent System Operator (MISO) oversees. The MISO market includes all of Wisconsin and Michigan, and portions of Ohio, Kentucky, Indiana, Illinois, Nebraska, Kansas, Missouri, Iowa, Minnesota, North Dakota, Montana and Manitoba, Canada. The MISO helps facilitate reliable, cost-effective systems and operations, dependable and transparent prices, open access to markets and planning for long-term efficiency. The MISO scope of operations includes over 127 GW of generation capacity, 93,600 miles of transmission and 280 participants. Coal is the primary marginal fuel and makes up approximately 51% of the region’s total generation capacity. The MISO does not have a formal, centralized forward capacity market, but LSEs do transact capacity through bilateral contracts.

BUSINESS

As discussed above under the heading “The Separation,” only the non-utility nuclear business of Entergy, including our 50% investment in EquaGen, will be included in the assets transferred to us in connection with our separation from Entergy. The following description of our business describes our business as it will be conducted by us.

Overview

We own six operating nuclear power plants, five of which are located in the Northeast United States, with the sixth located in Michigan. Our nuclear power plants have nearly 5,000 MW of electric generation capacity and we are primarily focused on selling the power produced by those plants to wholesale customers. Our revenues are primarily derived from sales of energy and sales of generation capacity. Our strategy is focused on providing safe and reliable electric power to our customers, while taking advantage of market trends and strategic investments that are consistent with our core values to enhance our revenues and operating income. We are the only publicly-traded, virtually emissions-free, nuclear generating company in the United States and believe that nuclear power is an important part of solving the problems of global climate change and energy independence.

The Northeast United States is a region that is experiencing a combination of high natural gas prices and constraints on the growth of supply, a dynamic we believe has contributed to power prices that are among the highest in the country. Due to these factors, as well as potential CO₂ legislation, we expect power prices in the Northeast to remain high over the next several years, providing us the opportunity to realize growth in our revenues and operating income.

We will operate and maintain our nuclear power plants through EquaGen, in which we hold a 50% ownership interest. Entergy Nuclear Operations, which will become a subsidiary of EquaGen prior to the separation, will be responsible for operating and making capital improvements to each nuclear power plant and complying with permits and approvals in accordance with the operating agreement for each plant, good utility practice, applicable laws and regulations, the applicable NRC operating license and the budgets approved by us for each plant. We also offer, or expect to offer, operations, management and decommissioning services to nuclear power plants owned by third parties in the United States. Through EquaGen, we believe we have a strong track record of maintaining, improving and safely operating nuclear power plants. Additionally, we believe we will be a leader in every aspect of the nuclear life cycle, including operations, license renewals, decommissioning estimates, acquisitions and dry fuel installations.

The following chart provides details regarding each of our operating nuclear power plants.

Vermont

Indian

FitzPatrick

Yankee

Pilgrim

Point 2

Point 3

Palisades

Market

NYISO

ISO-NE

NYISO

MISO

Year Acquired

2000

2002

1999

2001

2000

2007

2007 Capacity

838 MW

605 MW

688 MW

1,028 MW

1,041 MW

798 MW

In-Service Year

1975

1972

1974

1976

1971

Current License
Expiration

2014

2012

2013

2015

2031

Expected Date for
Approval of
Renewed License⁽¹⁾

May 2008

November 2008

July 2008

March 2010

Renewed
License
Issued on
January 17,
2007

2005-2007 Average Capacity Factor

93%

91%

95%

92%

80%⁽²⁾

Type of Reactor

Boiling
Water
Reactor

Pressurized
Water Reactor

Pressurized
Water
Reactor

Reactor Manufacturer

General
Electric

Westinghouse

Combustion
Engineering

(1) The estimated dates are the currently published dates from the NRC, and are based on our current expectations of when we would receive approval from the NRC for the renewal of our licenses. Those dates are subject to uncertainty, however, because of various factors, including the possibility of numerous interveners in the proceedings. For further information, see “Risk Factors—Risks Relating to our Business.”

(2) Palisades was acquired in April 2007, and as a result, the average capacity factor was calculated for the months of April through December 2007.

We also own two non-operating facilities, Big Rock Point in Michigan and Indian Point 1 in New York, which we acquired when we purchased the Palisades and Indian Point 2 nuclear plants. These facilities are in various stages of the decommissioning process.

Our Strengths

We believe that we are well positioned to execute our business successfully because of the following competitive strengths.

We have a strong track record of safety and security, and a reputation as a strong nuclear operator with fleet capability factors in the top quartile of the industry.

We have a strong track record of safety and security. Entergy Nuclear Operations, Inc. has achieved positive results in the periodic nuclear power plant evaluations conducted by the Institute of Nuclear Power Operations, an organization established by the nuclear power industry to promote high standards of safety and reliability in the operation of nuclear power plants. Furthermore, successful NRC-evaluated Force-on-Force exercises—exercises designed by the NRC to assess a nuclear power plant’s security—were conducted at three sites in September and October 2006, including Indian Point Energy Center and two regulated nuclear power plants to remain with Entergy after the separation. In addition, federally evaluated (by the NRC, the Department of Homeland Security and Federal Emergency Management Agency (FEMA)) emergency planning exercises were successfully completed at all six sites in 2006 and 2008. New standardized industrial best safety practices and procedures, which we have started implementing at Palisades and Indian Point Energy Center, were implemented at our other four nuclear power plants in 2005, including pre-outage safety readiness team assessments, rapid observation trending and safety project reviews for outage work. Each of these evaluations and initiatives highlight our focus on providing safe, secure and reliable nuclear power.

As demonstrated by the following metrics, we have a proven track record as a strong nuclear operator with repeated success in acquiring underperforming assets and materially improving key efficiency factors and performance. Entergy Nuclear Operations, Inc.’s operational expertise has contributed to an average improvement in capability of 15% for our nuclear power plants since 1999. In 1997, prior to the acquisition of any nuclear power plants by Entergy’s non-utility nuclear business, the six plants in our portfolio had an average capability factor of 76.3%. For the 12 months ended December 31, 2007, our nuclear power plants, excluding the Palisades nuclear power plant which we acquired in April 2007, rose to an average capability factor of 92.7%. Similarly, the loss rate resulting from forced outages has declined materially since Entergy’s acquisition of our nuclear power plants. In 1997, prior to the acquisition of any nuclear power plants by Entergy’s non-utility nuclear business, forced loss rates averaged 12.5%, while, for the 12 months ended December 31, 2007, our loss rates, excluding Palisades, declined to an average of 2.4%. The significant operating improvement at our nuclear power plants is also supported by a reduction in refueling outage duration under Entergy Nuclear Operations, Inc.’s management, with outage days falling 35% from 45 days in 1999 to 29 days in 2006. Outage performance continues to be strong, with the average refueling outage duration lasting 31 days in 2007, including the Palisades outage in the fall of 2007.

These operating improvements, as well as the overall implementation of best practices across our nuclear power plants, the elimination of functional redundancies, the capturing of synergies where possible and the development of teams of experts to transfer lessons learned across our nuclear power plants, have driven material cost reductions across our nuclear power plants. Prior to Entergy’s ownership of our nuclear power plants, the three-year average production cost per MWh for the period ending December 31, 1997 was $28. Under our management, three-year average production cost per MWh, which does not include Palisades, has decreased to $20 for the period ending December 31, 2007.

Our nuclear power plants are located in robust power markets.

Our Northeast nuclear power plants are located primarily in the New York and New England power markets, and sell power into the West and Hudson Valley regions of the NYISO and the Massachusetts and Vermont regions of the ISO-NE, which regions had among the highest average power prices in the United States during 2007: $53/MWh for the West region of the NYISO, $72/MWh for the Hudson Valley region of the NYISO and $68/MWh for the Massachusetts regions of the ISO-NE. We believe that the New York and New England power markets are experiencing a combination of a demand/supply imbalance, exposure to high natural gas prices and capacity market development, which are factors that we believe will benefit us as follows:


	•	Rising natural gas prices. As natural gas power plants set the price of power for a majority of the time in the Northeast markets, power prices have tended to have a strong positive correlation to the price of natural gas. Natural gas prices have trended upwards over the last several years, thus lifting power prices as well. Natural gas prices at the Henry Hub, a point along the natural gas pipeline located in Louisiana with the most liquid price point in the United States for natural gas, have trended upward from an average of $2.00/MMBtu throughout most of the 1990s to $5.80/MMBtu over the past seven years and an average of $6.95/MMBtu in 2007. At the same time, natural gas prices in the Northeast United States have also trended upward, and gas prices in the Northeast United States have remained high when compared to prices at the Henry Hub. In the winter, when demand for natural gas for space heating is the highest in the Northeast, the spread in gas prices between New York and Henry Hub tends to widen sharply. For example, the New York to Henry Hub natural gas price spread climbed from a monthly average of $0.56/MMBtu from April 2006 to October 2006, to $4.75/MMBtu in the winter of 2006/2007. In general, the persistent tightness in natural gas supplies in the Northeast markets relative to other U.S. markets has provided enough support for the spread in gas prices between the Northeast and Henry Hub to widen steadily in the last seven years. We believe this increase in natural gas prices has contributed to the increasing power prices in the Northeast markets in which we operate.

	•	Supply/demand imbalance. Based on current generating capacity, ISO-NE and NYISO are expected to fall below their minimum required reserve capacity by 2011 and 2010, respectively. This


		demand/supply imbalance is expected to contribute to continued increases in power prices as more inefficient power plants begin to set the price of power.


	•	Capacity market development. ISO-NE and NYISO have developed capacity markets in their respective regions to encourage investment in new generation and ensure system reliability. In addition to the revenue our power plants receive for power sold, we also receive payments related to our amount of total capacity that is uncontracted but still available to provide power to the region. For the year ended December 31, 2007, revenues from sales of capacity represented approximately 4% of our operating revenues.

We believe we are well positioned to benefit from CO₂ regulation.

The core generating functions of our nuclear-fueled power plants do not emit carbon dioxide. By contrast, we expect other non-nuclear power plants that typically set the price of power in the markets in which we operate will be required to incur costs to comply with expected carbon dioxide regulation because those power plants emit carbon dioxide. Because those increased costs are expected to result in higher power prices in our markets, we expect to generate increased net revenue as a result.

We expect to generate additional cash flow growth as long-term contracts with below-market prices expire and power is sold at higher market prices or we renegotiate contracts at higher prevailing market rates.

The majority of the existing long-term contracts on our five Northeast nuclear power plants expire by the end of 2012. Most of those existing contracts have contract prices that are lower than currently prevailing market prices. For example, our average contracted energy price for our portfolio in 2008 is $54/MWh while the current market prices in the West and Hudson Valley regions of New York and the New England regions are $76/MWh, $101/MWh and $97/MWh, respectively. As our existing contracts expire, we expect to benefit from the expected increase in power prices in the New York and New England markets as we begin to sell power at current market prices or we renegotiate contracts at higher prevailing market rates.

Relative to generators that utilize fossil fuels, an environment of potentially rising fuel cost is expected to have a smaller adverse effect on our net revenue.

We have established inventory and entered into a series of forward contracts to acquire nuclear fuel, under a mix of fixed and market price arrangements, for almost all of our expected generation through 2010. While the market-priced portion of our requirements will be exposed to potentially rising fuel prices, we do not expect the effect on our net revenue (operating revenues less fuel and fuel-related expenses) to be overly burdensome because fuel costs represent a small fraction of our revenues. For the fiscal year ended December 31, 2007, for example, our fuel expense was 8% of our operating revenues. Moreover, on a per unit of generation basis, nuclear fuel is less expensive than coal or natural gas fuel sources. According to the Nuclear Energy Institute, in 2006, nuclear fuel cost 0.46 cents per kWh generated (in 2006 cents) versus a cost of 1.83 cents per kWh for coal and 6.23 cents per kWh for natural gas.

In addition, we believe that ownership of a fleet of our scale allows us to realize nuclear fuel procurement synergies by reducing enriched uranium procurement costs while assuring supply. This is achieved through diversifying suppliers and processors, expanding the contract portfolio and including flexibility in delivery and utilization.

We expect EquaGen to provide us with operational diversity and growth opportunities.

We have a strong track record as a nuclear operating company and believe we will be a leader in every aspect of the nuclear life cycle, including operations, license renewal, decommissioning estimates and acquisitions. Immediately after the separation, we will be operating single-unit, multi-unit and multi-vendor sites representing three major U.S. nuclear steam supply systems: three General Electric boiling water reactors one Combustion Engineering pressurized water reactor and two Westinghouse pressurized water reactors. We believe that this operational diversity gives us a performance-based breadth of experience that we believe is unmatched in the industry.

In addition to operating our nuclear power plants, we also expect to offer nuclear services, including decommissioning, plant relicensing and plant operations, to third parties. As a diversified and experienced nuclear operator, we expect to be well positioned to grow our operating business by being able to offer sophisticated nuclear operating expertise, as well as ancillary nuclear services, to third parties. In addition, we will own Entergy Nuclear Nebraska, LLC, which will provide third-party services to the Cooper Nuclear Station owned by the Nebraska Public Power District. EquaGen will provide services to the Cooper Nuclear Station and to other third parties.

We have a strong and experienced management team.

We will be led by a strong management team consisting of leaders in the power industry with extensive industry expertise and established track records of success. President and CEO Richard Smith has over 30 years of experience in the electric utility industry and over 10 years of experience as an executive officer. In his current role at Entergy, he serves as the president and chief operating officer of Entergy. Chief Operating Officer John McGaha has over 30 years of experience with Entergy’s nuclear program, currently serving as president of planning, development and oversight for Entergy Nuclear Operations, with responsibility for planning and innovation, business development and new nuclear plant activities. John McGaha also has five years of service with the U.S. Navy Nuclear Powered Submarine Program and spent two and a half years designing coal-fired plants for Brown & Root.

Members of our management team played a direct role in building Entergy’s nuclear enterprise. Their select acquisitions of nuclear assets began prior to the upturn in commodity prices. This team has demonstrated valuable insight into future market trends and an ability to capitalize on significant value-enhancing opportunities in the sector. The leadership team has also proven its exceptional operations management skills by enhancing our nuclear power plants’ operating capabilities and capitalizing on synergies and value-creation opportunities across the fleet, transforming a collection of disparate assets into a cohesive, strong, stand-alone enterprise.

With strong industry, technical and regulatory knowledge, as well as decades of experience working with nuclear generation, we believe our management team is well-equipped to effectively lead our company through our transition to an independently-run company and also to respond to and take advantage of evolving market dynamics.

We do not expect a need to add funds to the decommissioning trusts for our plants to meet current NRC requirements.

We believe that the decommissioning funds for our nuclear generating stations and the expected earnings on those funds are sufficient to meet current NRC requirements and, consequently, we do not expect a need to contribute additional funds to the decommissioning trusts in the future.

Our Strategy

Our strategy is guided by a set of core values that informs all of our decisions.


	•	We are committed to safe, secure, reliable nuclear operations. Providing safe, secure, reliable nuclear power is our top priority. Our highly skilled work force has a proven track record of safely operating nuclear power plants.

	•	Our primary focus will be on nuclear power. We believe that nuclear power is an important part of solving the problems of global climate change and energy independence. To that end, we will look for ways to make disciplined strategic investments in nuclear power in the future.

	•	Our decision-making process will be guided by our point of view. Power and commodity markets are key drivers of our business. Due to the dynamic nature of these markets, our decision-making process will be guided by our short- and long-term view on the direction of power and commodity markets. We believe that this point of view approach to decision-making will provide us with the flexibility to capitalize on opportunities in an evolving marketplace and will guide a wide range of strategic decisions in a fluid, real-time manner, including:


	•	Hedging contracts. We do not have a pre-determined target hedge level for our nuclear generation portfolio. The size and duration of our power hedging contracts, especially as our existing hedging contracts begin to expire, will, to a large extent, be determined by our point of view on future market power prices and how they compare to the price and terms offered by hedge counterparties at a particular time.

	•	Capital investment. We remain open to pursuing diversity in our asset base. Our point of view on power and commodity markets at a particular time will help us evaluate the economic suitability of specific fuels, technologies, geographic regions and dispatch types. We expect that every opportunity, including greenfield development and asset acquisitions, will be evaluated utilizing this point of view approach to decision-making.


	•	We believe that a creative and skilled work force is a critical element of our performance. We seek to attract, train and retain best-in-class leaders in the power industry who are creative and dedicated to our core values.

	•	We are committed to operating our company in a financially responsible manner. We aim to maintain sufficient financial liquidity and an appropriate capital structure and credit rating to support safe, secure and reliable operations even in volatile market environments. We expect to return cash flows that are greater than needed for investment to shareholders in a timely manner. We anticipate that our primary manner of returning capital to shareholders will be through share repurchase programs.

	•	We are committed to operating our company in a socially responsible manner. We are dedicated members of the communities in which we live and have a history of giving back to those communities. We are dedicated to considering environmental effects in all of our investment decisions and continuing our strong tradition of community involvement.

Our Company

Energy and Capacity Sales

terminology and payment mechanics vary in these contracts, each of these types of contracts requires us to deliver MWh of energy to our counterparties, make capacity available to them, or both.

The following is a summary as of December 31, 2007 of the amount of our nuclear power plants’ planned energy output that is currently sold forward:


	2008		2009		2010		2011		2012

Contracted Sale of Energy:
Percent of planned energy output sold forward:
Unit-contingent(1)		51%		48%		31%		29%		16%
Unit-contingent with guarantee of availability(2)		36%		35%		28%		14%		7%
Firm liquidated damages(3)		5%		0%		0%		0%		0%

Total		92%		83%		59%		43%		23%
Planned energy output (TWh)		41		41		40		41		41
Average contracted price per MWh(4)		$54		$61		$58		$55		$51


(1)		A unit-contingent transaction is one where power is supplied from a specific generation asset; if the asset is unavailable, the seller is not liable to the buyer for any damages.

(2)		A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event we, the seller, fail to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of our outstanding guarantees of availability provide for dollar limits on our maximum liability under such guarantees.

(3)		A firm liquidated damages transaction requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific generation asset); if a party fails to deliver or receive energy, the defaulting party must pay a liquidated damages amount to the other party, as specified in the contract.

(4)		The Vermont Yankee acquisition included a 10-year PPA under which the former owners will buy most of the power produced by the plant through the expiration of the current operating license for the plant in 2012. The PPA includes an adjustment clause under which the prices specified in the PPA will be adjusted downward monthly, beginning in November 2005, if power market prices drop below the PPA prices.


	2008		2009		2010		2011		2012

Contracted Sale of Capacity:
Percent of capacity sold forward:
Bundled capacity and energy contracts		27%		26%		26%		26%		19%
Capacity contracts		59%		34%		16%		9%		2%

Total		86%		60%		42%		35%		21%
Planned net MW in operation		4,998		4,998		4,998		4,998		4,998
Average capacity contract price per kW per month		$1.8		$1.7		$2.5		$3.1		$3.5

Blended energy and capacity (based on revenues):
% of planned energy and capacity sold forward		89%		79%		51%		35%		17%
Average contract revenue per MWh		$56		$62		$59		$56		$52

Palisades’s current output is fully contracted to Consumers Energy through 2022; however, we are considering implementation of an increase in the generating capacity at the Palisades facility. We expect this process, which is called a power uprate program, to result in up to an additional 28 MW (4 MW in 2009 and 24 MW in 2011) of additional capacity that will be available for sale into the MISO power market. This output will represent approximately 3.5% of total expected output from the Palisades facility.

Customers

Our customers for the sale of both energy and capacity include retail power providers, utilities, electric power co-operatives, power trading organizations and other power generation companies. As of December 31, 2007, a majority of our contracted energy has been sold to 17 counterparties under 55 separate transactions, and a majority of our contracted capacity has been sold to 13 counterparties under 29 separate transactions. No single customer accounts for more than 10% of our revenues, and as of December 31, 2007, approximately 96% of our counterparty exposure from energy and capacity contracts is with counterparties with investment grade ratings.

Competition

The ISO-NE and NYISO markets are highly competitive. We have approximately 85 competitors in New England and 70 competitors in New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. We are an independent power producer, which means we generate power for sale to third parties at market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants.

Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. As of December 31, 2007, our plants provided approximately 7% of the aggregate net generation capacity serving the New England power market and 14% of the aggregate net generation capacity serving the New York power market.

The MISO market includes 280 participants. The MISO does not have a formal, centralized forward capacity market, but LSEs do transact capacity through bilateral contracts. Palisades’s current output is fully contracted to Consumers Energy through 2022 and, therefore, we do not expect to be materially affected by competition in the MISO market in the near term.

Seasonality

Our revenues and operating income are subject to mild fluctuations during the year due to seasonal factors and weather conditions. When outdoor and cooling water temperatures are lower, generally during colder months, our nuclear power plants operate more efficiently, and consequently, we generate more electricity and we record higher revenues and operating income. Although some of our annual contracts provide for monthly pricing, we derive the majority of our revenues from fixed price forward power sales that are generally sold at a single price for a calendar year, which can offset the effects of seasonality and weather conditions on monthly power prices.

Fuel Supply

The nuclear fuel cycle consists of the following:


	•	mining and milling of uranium ore to produce a concentrate;

	•	conversion of the concentrate to uranium hexafluoride gas;

	•	enrichment of the hexafluoride gas;

	•	fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and

	•	disposal of spent fuel.

The enriched uranium requirements for Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, Vermont Yankee and Palisades are met pursuant to contracts made by Entergy Nuclear Fuels Company (ENFC), our wholly-owned subsidiary. ENFC is responsible for contracts to acquire nuclear materials, except for fuel

fabrication, for our nuclear power plants, while Entergy Nuclear Operations, Inc. acts as our agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the Department of Energy (DOE) and each of our nuclear power plants.

Based upon currently planned fuel cycles, our nuclear units have a diversified portfolio of contracts and inventory that provide substantially adequate nuclear fuel materials and conversion and enrichment services at what we believe are reasonably predictable prices through 2009. Our ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the creditworthiness and reliability of uranium miners, as well as upon the structure of our contracts for the purchase of nuclear fuel. For example, some of the supply under our contracts for nuclear fuel is effectively on a “mine-contingent” basis, which means that if applicable mines are unable to supply sufficient uranium, we may be required to purchase nuclear fuel from another supplier. Furthermore, although we have access to uranium supplies, the pricing for nuclear fuel is dependent upon the market for uranium supply. The market for uranium supply became extremely limited in 2006 and 2007 and market pricing has been highly volatile during this period. Market prices for uranium concentrates have risen from about $7 per pound in December 2000 to a 2007 range of $70 to $135 per pound.

The rising nuclear fuel market prices will affect the U.S. nuclear utility industry, including us, first in our cash flow requirements for fuel acquisition, and then, some time later, in our nuclear fuel expense. For example, for a nuclear fleet the size of ours, the current market value of annual enriched uranium requirements has increased by several hundred million dollars compared to about five years ago. As nuclear fuel installed in the core in nuclear power plants is replaced fractionally over an approximate five-year period, nuclear fuel expense will eventually, with a time lag, reflect current market prices and can be expected to increase from the current reported industry levels of about 0.5 cents per kWh to 1.0 cent per kWh or higher. Our nuclear fuel contract portfolio provides a degree of price hedging against the full extent of market prices through 2009, but market trends will eventually affect the costs of all nuclear plant operators.

Other Operations

Contract management and Entergy Nuclear Power Marketing

After the separation, we will continue to provide contract management and other power marketing services through Entergy Nuclear Power Marketing, LLC (ENPM), which will be a wholly-owned subsidiary of us. ENPM was formed in April 2006 to centralize the power marketing function for our non-utility nuclear operations. In connection with its formation, ENPM entered into long-term power purchase agreements with each of our subsidiaries that own one of our nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions, generation scheduling, contract management (including billing and settlements) and market and credit risk mitigation.

Entergy Nuclear Nebraska, LLC

In September 2003, we agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The contract is for 10 years, the remaining term of the plant’s operating license. We will receive $14 million in each of the remaining years of the contract. We can also receive up to $6 million more per year if safety and regulatory goals are met. In addition, we will be reimbursed for all employee-related expenses. In 2006, we signed an agreement to provide license renewal services for the Cooper Nuclear Station.

Our History and Development

Enexus Energy was incorporated as a Delaware corporation on April 18, 2008. Entergy contributed $1 for 100 shares of our common stock in a private placement transaction exempt from registration under Section 4(2) of the Securities Exchange Act of 1934, as amended. Enexus Energy is currently a wholly-owned

subsidiary of Entergy that was organized to effectuate the separation of Entergy’s non-utility nuclear business. Below is a brief timeline summarizing the history and development of Entergy’s non-utility nuclear business.



1971		Palisades commenced commercial operation.

1972		Vermont Yankee and Pilgrim commenced commercial operation.

1974		Indian Point 2 commenced commercial operation.

1975		James A. FitzPatrick commenced commercial operation.

1976		Indian Point 3 commenced commercial operation.

1998		Entergy formed a nuclear business development group, headquartered in Jackson, Mississippi, to pursue a growth strategy in areas outside the company’s utility service area. The group’s goal was for Entergy to become a leading national operator of nuclear power plants.

1999		Entergy purchased Boston Edison’s Pilgrim Station, the first ever U.S. nuclear plant sale by a utility through a competitive bidding process.

2000		Entergy purchased Indian Point Unit 3 and the James A. FitzPatrick plant from the New York Power Authority.

2001		Entergy purchased Indian Point Unit 2 from Consolidated Edison.

2002		Entergy purchased Vermont Yankee from Vermont Yankee Nuclear Power Corporation.

2003		Entergy began providing management services to Nebraska Public Power District for its Cooper Nuclear Station.

2007		Entergy purchased the Palisades nuclear power plant in Michigan from Consumers Energy.

		Entergy announced that its board of directors unanimously decided to pursue a plan to separate its utility and non-utility nuclear businesses into two publicly-traded companies.

ENVIRONMENTAL MATTERS

Our facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that our facilities and operations are in substantial compliance with currently applicable environmental regulations. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely predicted.

Clean Air Act and Subsequent Amendments

The Clean Air Act and its subsequent amendments (Clean Air Act) established several programs that heavily regulate fossil-fueled generation facilities. Nuclear facilities do not emit regulated air pollutants as part of their generating operations. However, some support functions operating at nuclear facilities, such as emergency diesel generators and house heating boilers, do emit regulated air pollutants at low levels. Of our facilities, only Palisades currently holds a federal (Title V) air pollution control operating permit. Our other facilities are permitted under state programs for minor sources of air pollutants, and Palisades may also qualify for minor source treatment under Michigan and federal law.

Nuclear facilities also do not emit CO₂ or other greenhouse gases from their core generating functions. Small levels of greenhouse gas emissions from support functions could require the investment of capital or the purchase of allowances in the future. Also, the advent of greenhouse gas regulation applicable to fossil-fueled generators but not applicable (or applicable to a much lesser extent) to nuclear facilities could positively influence the price structure of the market into which our facilities sell electricity.

Future Legislative and Regulatory Developments (Air)

In addition to the specific instances described above, there are a number of legislative and regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state and local level. Initiatives that could influence the financial success of the operation of our nuclear facilities include:


	•	designation by the Environmental Protection Agency (EPA) and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

	•	introduction of several bills in Congress proposing further limits on NOx, SO₂, mercury or limits on CO₂ emissions;

	•	pursuit by the Bush administration of a voluntary program intended to reduce CO₂ emissions and efforts in Congress to establish a mandatory federal CO₂ emission control structure;

	•	passage of the RGGI by ten states in the Northeast United States;

	•	the agreement by several Midwestern governors to a greenhouse gas reduction plan;

	•	efforts by certain external groups to encourage reporting and disclosure of CO₂ emissions and risk; and

	•	litigation filed by states and environmental advocacy groups in the D.C. Circuit (Coke Oven Environmental Task Force v. EPA) asking the court to require the EPA to promulgate regulations under existing provisions of the Clean Air Act to control the emissions of CO₂ from power plants. In April 2007 the U.S. Supreme Court held that the EPA is authorized by the current provisions of the Clean Air Act to regulate emissions of CO₂ and other “greenhouse gases” as “pollutants” (Massachusetts v. EPA) and that the EPA is required to regulate these emissions from motor vehicles if the emissions are anticipated to endanger public health or welfare. The Supreme Court directed the EPA to make further findings in this regard. The decision is expected to affect the similarly positioned Coke Oven case pending in the U.S. Court of Appeals for the D.C. Circuit and considering the same question under a similar Clean Air Act provision in the context of CO₂ emissions from electric generating units. Although we cannot predict how the D.C. Circuit or the EPA will react to the Supreme Court decision, one outcome could be a decision to regulate, under


		the Clean Air Act, emissions of CO₂ and other “greenhouse gases” from motor vehicles or from power plants.

We continue to monitor these and similar actions in order to analyze their potential operational and cost implications and benefits.

Clean Water Act

The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act or CWA) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The CWA requires all discharges of pollutants to waters of the United States to be permitted, and section 316(b) of the CWA regulates cooling water intake structures.

316(b) Cooling Water Intake Structures

The EPA finalized new regulations in July 2004 governing the intake of water at large existing power plants that employ cooling water intake structures. The rule sought to reduce perceived effects on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic effects. Entergy, other industry members and industry groups, environmental groups and a coalition of Northeast and Mid-Atlantic states challenged various aspects of the rule. On January 25, 2007, the United States Court of Appeals for the Second Circuit remanded the rule to the EPA for reconsideration. The court instructed the EPA to reconsider several aspects of the rule that were beneficial to the regulated community after finding that these provisions of the rule were contrary to the language of the Clean Water Act or were not sufficiently explained in the rule. In April 2008, the United States Supreme Court agreed to review the decision of the Second Circuit on the question of whether the EPA may take into consideration a cost-benefit analysis in developing these regulations, a consideration beneficial to us that the Second Circuit disallowed. Entergy is one of the petitioners who sought Supreme Court review. After the Supreme Court rules on this issue, the EPA may eventually reissue a rule similar in structure to the rule remanded by the court but with additional content designed to meet the court’s concerns, or the EPA may issue a rule with a substantially different structure and effect. Until the EPA issues guidance to the regulated community on what actions should be taken to comply with the Clean Water Act, and until the form and substance of the new rule itself is determined, it is impossible to gauge the effect of the court’s decision on our business. We continue to monitor this action.

We are currently in various stages of the data evaluation and discharge permitting process for our nuclear power plants. We are involved in an administrative permitting process with the New York environmental authority for renewal of the Indian Point 2 and 3 discharge permits. In November 2003, the New York State Department of Environmental Conservation (NYDEC) issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental impacts attributable to the intake of cooling water at Indian Point 2 and Indian Point 3. The draft permit would require us to take certain steps to assess the feasibility of retrofitting the site to install cooling towers because we have announced our intent to apply for NRC license renewal at Indian Point 2 and Indian Point 3. Upon its becoming effective, the draft permit would also require the facilities to take an annual 42 unit-day outage (coordinated with the existing refueling outage schedule) and provide a payment into a NYDEC account until the start of cooling tower construction. We are participating in the administrative process to request that the draft permit be modified prior to final issuance and we oppose any requirement to install cooling towers or to begin annual outages at Indian Point 2 and Indian Point 3. We notified the NYDEC that the cost of retrofitting Indian Point 2 and Indian Point 3 with cooling towers likely would cost, in 2003 dollars, at least $740 million in capital costs and an additional $630 million in lost generation during construction. Due to fluctuations in power pricing and because a retrofitting of this size and complexity has never been undertaken, significant uncertainties exist in these estimates and, therefore, could be materially higher than estimated.

In March 2008, NYDEC issued a draft discharge permit and a draft water quality certification for FitzPatrick, opening a 30-day public comment period on these documents. The certification, or a waiver or exemption of the same, is required by section 401 of the federal Clean Water Act as a supporting document to the NRC’s license renewal decision. The discharge permit action is not related to the license renewal decision. NYDEC received comments on the draft documents from Entergy and from the public, and New York law requires that a hearing now be held on these public comments prior to the issuance of a final discharge permit or water quality certification. In response, NYDEC issued a draft denial without prejudice of the certification and is required to begin hearings on both draft documents in the near term. FitzPatrick, having filed a timely and complete application for permit renewal, continues to operate under its former discharge permit.

Our other generation facilities are in the process of reviewing data, considering implementation options, and providing information required by the EPA and the affected states. Deadlines for determining compliance with the rule and for any required capital or operational expenditures are unknown at this time due to the remand of the rule to the EPA.

Vermont Yankee NPDES Matter

Opposition groups appealed a final permit issued to Vermont Yankee pursuant to the NPDES in which the Vermont Agency of Natural Resources (VANR) allowed a small increase in the amount of heat the facility can discharge to the Connecticut River from June 16 to October 14 each year. The VANR permit increases operational flexibility for the required usage rate of the existing cooling towers and for the generation rate of the facility that is especially helpful in conditions of high ambient temperatures and/or low river flow conditions. The trial of this matter took place in the Vermont Environmental Court during the summer of 2007; a decision is expected in 2008. The court issued a stay of the modified permit late in the 2006 summer period, and the stay remains in effect. A reversal of the permit would require that Vermont Yankee return to its previous thermal discharge permit limits with the loss of operational flexibility.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint and several liabilities on responsible parties. Our generation plants have sent waste materials to various disposal sites over the years, and releases have occurred at our facilities. Some disposal sites used by our facilities have been the subject of governmental action under CERCLA, resulting in site clean-up activities. Our predecessors in interest have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs.

Environmental laws now regulate certain of our operating procedures and maintenance practices that historically were not subject to regulation. Additionally, we must comply with other environmental laws and regulations on the federal, state and local levels applicable to the storage, on-site management, transportation and disposal of hazardous waste. Under these various laws and regulations, we could incur penalties for noncompliance or substantial costs to restore contaminated properties consistent with the various standards. We conduct studies to determine the extent of any required remediation and have recorded reserves based upon our evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites could be identified which require environmental remediation for which we could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:


	•	Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.

	•	The identification of additional sites or the filing of other complaints in which we may be asserted to be a PRP.

	•	The resolution or progression of existing matters through the court system or resolution by the EPA.

Other Environmental Matters

As part of licensing conditions, the NRC requires nuclear power plants to regularly monitor and report the presence of certain radioactive material in the environment. Entergy joined other nuclear owners and the Nuclear Energy Institute in 2006 to develop a groundwater initiative monitoring program. This initiative began after detection of radioactive material, primarily tritium, in groundwater at several plants in the United States, including our Indian Point Energy Center. In addition to tritium, other radionuclides, such as strontium, have been detected in on-site groundwater at Indian Point Energy Center. Lower levels of tritium have also been found at the Pilgrim and Palisades plants, and those sites are currently conducting investigations to address these findings.

As part of the groundwater monitoring initiative program, at our nuclear sites we have: (1) reviewed plant groundwater characteristics (hydrology) and historical records of previous events on-site that may have potentially affected groundwater; (2) implemented fleet procedures to manage events that could potentially effect groundwater; and (3) installed groundwater monitoring wells and begun periodic sampling. This program also includes protocols for voluntarily notifying federal, state and local officials if contamination is found in groundwater, and for actively addressing contamination to the extent required.

In cooperation with regulators and interested parties, Entergy completed a comprehensive site characterization and groundwater investigation at Indian Point Energy Center, including finding that certain conditions at the site ultimately migrate and discharge to the Hudson River. The investigation concluded that there is no indication of adverse environmental or health risk to either the site or the Hudson River. Remedial actions are underway and we expect them to be completed in 2008. In October 2007, the EPA announced that it was consulting with the NRC and the NYDEC regarding Indian Point Energy Center. The EPA stated that after reviewing data it confirmed with NYDEC that there have been no violations of federal standards for radionuclides in drinking water supplies.

EMPLOYEES, PROPERTIES AND FACILITIES,
GOVERNMENT REGULATION AND LEGAL PROCEEDINGS

Employees

At the time of the separation, we expect to have up to 4,121 employees, all full-time. We expect that up to 140 of those employees will be employed by Enexus and that the remainder will be employed by EquaGen.

As of March 31, 2008, approximately 1,738 Entergy Nuclear Operations employees were represented by local union affiliates of the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the Michigan State Utility Workers Council and the United Government Security Officers of America. The terms and conditions of employment for these represented employees are generally governed by collective bargaining agreements. The terms of the collective bargaining agreements expire at various times and some will be subject to negotiations before the separation.

Properties and Facilities

Generating Stations

We own the following nuclear power plants:


				License
				Expiration
Power Plant	Acquired	Location	Reactor Type	Date

Pilgrim	July 1999	Plymouth, MA	Boiling Water Reactor		2012
FitzPatrick	Nov. 2000	Oswego, NY	Boiling Water Reactor		2014
Indian Point 3	Nov. 2000	Buchanan, NY	Pressurized Water Reactor		2015
Indian Point 2	Sept. 2001	Buchanan, NY	Pressurized Water Reactor		2013
Vermont Yankee	July 2002	Vernon, VT	Boiling Water Reactor		2012
Palisades	Apr. 2007	South Haven, MI	Pressurized Water Reactor		2031

We also obtained by purchase of the Palisades and Indian Point assets, two non-operating sites, Big Rock Point in Michigan and Indian Point 1 in New York, respectively. These plants are in various stages of the decommissioning process.

Our corporate headquarters are located at Jackson, Mississippi.

We believe we have satisfactory title to our plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in our opinion, would not have a material adverse effect on the use or value of our portfolio. We believe that our properties are adequate and suitable for the conduct of our business in the future.

Interconnections

The Pilgrim and Vermont Yankee plants are a part of ISO-NE and the FitzPatrick and Indian Point plants are part of the NYISO. The Palisades plant is part of the MISO. The primary purpose of the ISO-NE is to direct the operations of the major generation and transmission facilities in the New England region and the primary purpose of the NYISO is to direct the operations of the major generation and transmission facilities in New York state. The primary purpose of the MISO is to direct the operations of the major generation and transmission facilities in 15 U.S. states and Manitoba.

Regulations Generally Applicable to Our Business

Public Utility Holding Company Act of 2005

The Public Utility Holding Company Act of 2005 (PUHCA 2005) is the successor statute to the now-repealed Public Utility Holding Company Act of 1935. PUHCA 2005 generally requires utility holding

companies and their subsidiaries to provide FERC and state utility commissions’ access to books and records, subject to certain criteria. Following the indirect acquisition of the six operating nuclear power plants, Enexus Energy will be a “holding company” subject to PUHCA 2005, but it and its subsidiaries will qualify for an exemption from FERC’s books and records requirements. Enexus Energy and its subsidiaries may still be obligated to provide state utility commissions with access to their books and records in certain situations.

Federal Power Act

Each of our subsidiaries that own one of our nuclear power plants and ENPM is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy. The Federal Power Act gives FERC jurisdiction over the rates charged by each such subsidiary and ENPM for capacity and energy produced by our nuclear power plants. FERC has accepted a tariff filing by each of the subsidiaries and ENPM that allows each such entity to sell power at prices set by the market.

Under the Federal Power Act, in addition to regulating wholesale sales and transmission of electric energy, FERC regulates:


	•	securities issuance by public utilities;

	•	direct and indirect disposition of jurisdictional electric facilities by a public utility;

	•	mergers and acquisitions involving public utilities and/or utility holding companies; and

	•	various accounting and interlocking director matters.

State Regulation

Some of our subsidiaries that own our nuclear power plants are subject to certain regulatory requirements by the state utility commission of the state in which its nuclear plant is located.

New York

The New York Public Service Commission has jurisdiction over New York electric corporations. The New York Public Service Commission has determined that wholesale generators – including nuclear generators – operating in New York come under the definition of electric corporations. The New York Public Service Commission has created a lightened regulatory regime for wholesale generators in New York, including nuclear generators. Accordingly, our Indian Point Energy Center and FitzPatrick nuclear power plants are subject to certain regulatory requirements under the New York State Public Service Law (New York PSL). Under the regulatory regime for our nuclear power plants, the New York Public Service Commission reviews, among other things, securities issuances, reorganizations and transfers of securities, works or systems.

The New York Public Service Commission has jurisdiction over changes in or transfers of corporate ownership interests of our Indian Point Energy Center and FitzPatrick nuclear power plants, in that the New York PSL requires approval by the New York Public Service Commission for electric corporations directly or indirectly acquiring the stock or bonds of any other corporation incorporated for, or engaged in the same or similar business in New York or any other state. The New York PSL also requires approval by the New York Public Service Commission for a stock corporation of any description, foreign or domestic, other than a gas, electric or street railroad corporation, to “purchase or acquire, take or hold,” more than 10% of the voting capital stock issued by an electric corporation. The New York Public Service Commission will not give its consent pursuant to the New York PSL unless it is shown the proposed transaction is in the public interest.

The New York Public Service Commission also has jurisdiction over our issuance of stocks, bonds and other forms of indebtedness payable at periods of more than 12 months after the date of issuance. The issuance of stocks, bonds and other forms of indebtedness must also be for a statutory purpose.

Additionally, the New York Public Service Commission has jurisdiction over reports on and the spending of decommissioning funds. The New York Public Service Commission has also retained jurisdiction over affiliated interests if our subsidiaries were to affiliate with a marketer in order to make sales that affect New York markets. In such an event our subsidiaries would remain subject to the New York PSL with respect to matters such as enforcement, investigation, safety, reliability, and system improvement, and the New York

Public Service Commission would have authority to implement a one-call notification system for the designation, marking, and protection of underground facilities.

Our FitzPatrick and Indian Point Energy Center nuclear power plants are also subject to reporting and monitoring requirements. These requirements include: the New York Public Service Commission documentation review (e.g., business plans, monthly reports, operating status reports and safety reports); notification requirements (e.g., filing of a notice with the New York Public Service Commission if a shutdown of a nuclear unit is planned); providing the New York Public Service Commission access to the plants; cooperating with New York State nuclear emergency preparedness efforts; and cooperating with special investigations into specific problems or events at the nuclear power plants.

On January 28, 2008, the owners of our FitzPatrick, Indian Point 2 and Indian Point 3 nuclear power plants (Entergy Nuclear FitzPatrick, LLC, Entergy Nuclear Indian Point 2, LLC and Entergy Nuclear Indian Point 3, LLC), as well as Entergy Nuclear Operations, Inc. and Enexus Energy, filed a petition with the New York Public Service Commission requesting a declaratory ruling regarding corporate reorganization or in the alternative an order approving the transaction and an order approving debt financing. Petitioners also requested confirmation that the corporate reorganization will not have an effect on Entergy Nuclear FitzPatrick, LLC’s, Entergy Nuclear Indian Point 2, LLC’s, Entergy Nuclear Indian Point 3, LLC’s, and Entergy Nuclear Operations, Inc.’s status as lightly regulated entities in New York, given that they will continue to be competitive wholesale generators.

Vermont

Entergy Nuclear Vermont Yankee, LLC, the owner of the Vermont Yankee plant, and Entergy Nuclear Operations are subject to regulation as public utility companies by the Vermont Public Service Board, which also has jurisdiction over persons owning or operating these two companies and over the Vermont Yankee plant. The Vermont Public Service Board has authority to conduct investigations of Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, and certain transactions by Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc., such as the issuance of stock or certain other instruments evidencing debt, security for debt such as mortgages or pledges, the sale or lease of certain utility property, and certain mergers, acquisitions or consolidations of or the direct or indirect change of a controlling interest in these companies, require the Vermont Public Service Board’s advance approval. Substantial changes to the Vermont Yankee plant also require such approval.

Entergy Nuclear Vermont Yankee, LLC and Entergy Nuclear Operations, Inc. cannot operate Vermont Yankee and cannot store in Vermont spent nuclear fuel generated after March 21, 2012, without the approval of the Vermont Public Service Board and the Vermont legislature. We have filed with the Vermont Public Service Board an application (as required by Vermont law) for approval of continued operation and storage of spent nuclear fuel generated after that date. Under Vermont law, the Vermont General Assembly must approve Entergy’s request. The Vermont General Assembly is not expected to take up the request until 2009. Vermont is the only state where we operate a nuclear plant that is subject to such a state requirement.

The separation and related transactions require the approval of the Vermont Public Service Board, see the section entitled “The Separation—Regulatory Approvals Necessary to Effect the Separation—State Regulatory Approvals.

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear power plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. We are subject to the NRC’s jurisdiction as the owner and, through our investment in EquaGen, operator of Pilgrim, Indian Point Energy Center, FitzPatrick, Palisades and Vermont Yankee. Substantial capital expenditures at our nuclear power plants because of revised safety requirements of the NRC could be required in the future.

Our Palisades nuclear power plant has already obtained a 20 year license renewal in January 2007 and we filed with the NRC in 2006 for license renewals for Pilgrim, FitzPatrick and Vermont Yankee. We expect to obtain 20-year license renewals for these three plants in 2008. In addition, in April 2007, we submitted an application to the NRC to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The NRC is required by statute to provide an opportunity to members of the public to request a hearing on the application. In early December 2007, the NRC received nine petitions to intervene in the license renewal proceeding for Indian Point 2 and Indian Point 3. The petitions were filed by various state and local government entities, including the States of New York and Connecticut, as well as several public interest groups. Collectively, the nine petitions contain over 160 proposed contentions, which are specific issues of law or fact pertaining to the license renewal application that the petitioners seek to have adjudicated by the NRC.

In January 2008, in accordance with the NRC’s hearing rules, we filed nine detailed responses to the petitions, opposing all of the petitioners’ proposed contentions. The NRC Staff, which functions as an independent party in any hearing, also filed detailed responses to the petitions. The NRC Staff opposed admission of all but a few of the petitioners’ proposed contentions. The NRC’s Atomic Safety and Licensing Board is expected to rule on the admissibility of the petitioners’ proposed contentions no earlier than late May 2008.

The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. We intend to participate fully in the hearing process as permitted by the NRC’s hearing rules. We believe that many of the issues raised by the petitioners are not germane to license renewal and will not be admitted for hearings. We will continue to work with the NRC Staff as it completes its technical and environmental reviews of the license renewal application, and we expect to obtain renewed licenses for Indian Point 2 and Indian Point 3.

Entergy Nuclear Operations, the current NRC-licensed operator of our six operating nuclear power plants, filed an application in July 2007 with the NRC seeking indirect transfer of control of the operating licenses for our six operating nuclear power plants, and supplemented that application in December 2007 to incorporate the planned business separation. Entergy Nuclear Operations, Inc. will remain the operator of those plants after the separation. In the December 2007 supplement to the NRC application, Entergy Nuclear Operations, Inc. provided additional information regarding the distribution, organizational structure, technical and financial qualifications and general corporate information. The NRC published a notice in the Federal Register establishing a period for the public to submit a request for hearing or petition to intervene in a hearing proceeding. The NRC notice period expired on February 5, 2008 and two petitions to intervene in the hearing proceeding were filed before the deadline. Each of the petitions opposes the NRC’s approval of the license transfer on various grounds, including contentions that the approval request is not adequately supported regarding the basis for the proposed structure, the adequacy of decommissioning funding and the adequacy of financial qualifications. Entergy submitted answers to the petitions on March 31 and April 8, and the NRC or a presiding officer designated by the NRC will determine whether a hearing will be granted. If a hearing is granted, the NRC is expected to issue a procedural schedule providing for limited discovery, written testimony and a legislative-type hearing. Under the NRC’s procedural rules for license transfer approvals, the NRC Staff will continue to review the application, prepare a Safety Evaluation Report and issue an approval or denial without regard to whether or not a hearing request is pending or has been granted. Thus, resolution of the hearing requests is not a prerequisite to obtaining the required NRC approval.

Nuclear Waste Policy Act of 1982

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Our subsidiaries that own our nuclear power plants provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected companies entered into contracts with the DOE, whereby the DOE will furnish disposal service at a cost of $0.001 per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Each of our subsidiaries that owns one of our nuclear power plants has accepted, as applicable, assignment of the Pilgrim, FitzPatrick, Indian Point 2, Indian Point 3, Vermont Yankee and

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Palisades/Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Our ongoing spent fuel fees are approximately $40 million per year.

The permanent spent fuel repository in the United States has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel. Because the DOE has not accomplished these objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. Furthermore, we are uncertain as to when the DOE plans to commence acceptance of spent fuel from our facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at our nuclear sites.

As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, our nuclear owner subsidiaries and EquaGen’s licensee subsidiaries have incurred and will continue to incur damages. In November 2003, these entities (but not the owner of the Palisades plant) commenced litigation to recover the damages caused by the DOE’s delay in performance. We cannot predict the timing or amount of any potential recoveries on other claims filed by our subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the United States Court of Federal Claims damage awards.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear power plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at FitzPatrick in 2002 and at Indian Point Energy Center in 2008. These facilities will be expanded as needed. Dry fuel storage construction is near completion at Vermont Yankee, and it is planned that casks will be loaded beginning in the first half of 2008. Current on-site spent fuel storage capacity at Pilgrim is estimated to be sufficient until approximately 2014; dry cask storage facilities are planned to be placed into service at that unit on or before 2014.

Nuclear Plant Decommissioning

As part of the Pilgrim, Palisades and Vermont Yankee purchases, Boston Edison, Consumers Energy Company and Vermont Yankee Nuclear Power Corporation, respectively, transferred decommissioning trust funds, along with the liability to decommission the plants, to us. We believe that the decommissioning trust funds will be adequate to cover future decommissioning costs for these plants without any additional deposits to the trusts.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, the NYPA retained the decommissioning trusts and the decommissioning liability. We entered into decommissioning agreements with NYPA that specify each party’s decommissioning obligations. NYPA has the right to require us to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to us. If the decommissioning liability is retained by NYPA, we will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. We believe that the amounts available to us under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. In connection with the Pilgrim acquisition, we received Pilgrim’s decommissioning trust fund. We believe that Pilgrim’s decommissioning fund will be adequate to cover future decommissioning costs for the plant without any additional deposits to the trust.

As part of the Indian Point 2 purchase, Consolidated Edison transferred the decommissioning trust fund and the liability to decommission Indian Point 2 to us. In addition, as part of the purchase of Indian Point 2, Consolidated Edison transferred to us the obligation to decommission the shutdown Indian Point 1 plant. We also funded an additional $25 million to the decommissioning trust fund, and we believe that the trust will be adequate to cover future decommissioning costs for Indian Point 1 and Indian Point 2 without any additional deposits to the trust funds.

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In April 2007, as part of the purchase of the Palisades nuclear energy plant located near South Haven, Michigan, Consumers Energy Company transferred to us the liability to decommission the plant, as well as related decommissioning trust funds. Also as part of the transaction, we assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, we will dismantle the spent fuel storage facility and complete site decommissioning. We expect to fund this activity from operating revenue, and we are providing $5 million in credit support to provide financial assurance for this obligation to the NRC.

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:


	•	The primary layer is private insurance underwritten by American Nuclear Insurers and provides public liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

	•	Under the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a 5% surcharge that may be payable, if needed, at a rate that is presently set at $15 million per year per nuclear power reactor. There are no terrorism limitations.

Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides approximately $10.4 billion in insurance coverage, in addition to the $300 million in primary coverage, to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

The limit is subject to change in the secondary layer assessments to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, we carry the maximum available amount of primary nuclear liability insurance (currently $300 million for each operating site). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages in excess of the $300 million in primary insurance coverage, each owner of a nuclear plant reactor will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the $300 million primary level, up to a maximum of $100.6 million per reactor per incident. The retrospective premium payment is currently limited to $15 million per year per reactor until the aggregate public liability for each licensee is paid up to the $100.6 million cap. This annual limit is subject to change to account for the effects of inflation.

Property Insurance

Our nuclear owner subsidiaries are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2007, Indian Point 2 (including Indian Point 1), Indian Point 3, FitzPatrick, Pilgrim, Vermont Yankee, Palisades, and the decommissioned Big Rock Point plant (primary layer only as approved by the NRC) were insured against such losses per the following structures:


	•	Primary Layer (per plant) - $500 million per occurrence;

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	•	Excess Layer - $615 million per occurrence;

	•	Total limit - $1.115 billion per occurrence; and

	•	Deductibles: $2.5 million per occurrence.

Indian Point 2 (including Indian Point 1) and Indian Point 3 share in the primary layer with one policy in common for that site because the policy is issued on a per site basis. Big Rock Point has its own primary policy with no excess coverage. Property coverage for facilities not covered by NEIL (i.e. off-site training facilities), are included in a separate insurance policy.

In addition, our nuclear power plants are also covered under NEIL’s Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2007:


	•	Indian Point 2 & 3 and Palisades (Indian Point 2 & 3 share the limits):

– $4.5 million weekly indemnity;

– $490 million maximum indemnity; and

– Deductible: 12 week waiting period;


	•	FitzPatrick and Pilgrim (each plant has an individual policy with the noted parameters):

– $4.0 million weekly indemnity;

– $490 million maximum indemnity; and

– Deductible: 12 week waiting period;


	•	Vermont Yankee:

– $4.0 million weekly indemnity;

– $435 million maximum indemnity; and

– Deductible: 12 week waiting period.

Under the property damage and accidental outage insurance programs, our nuclear power plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2007, the aggregate maximum amounts of such possible assessments per occurrence were $86.8 million. We maintain property insurance for our nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. The NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of non-certified terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. There is no aggregate limit involving one or more acts of certified terrorism.

Indian Point Energy Center Emergency Notification System

Pursuant to federal law and an NRC order, our Indian Point Energy Center located in Buchanan, New York is required to install a new siren emergency notification system with certain backup power capabilities. Due to the complexity of the technology employed in this system, among other things, Entergy Nuclear Operations, Inc., the operator of our nuclear power plants and a subsidiary of EquaGen, was unable to meet the April 15, 2007 operability date previously approved by the NRC. Because of this delay, the NRC fined Entergy Nuclear Operations $130,000. Subsequently, the NRC set a new deadline of August 24, 2007 for implementation of the new siren system and this new deadline was also not satisfied. On January 24, 2008, the NRC fined Entergy Nuclear Operations, Inc. $650,000 for the continuing delay in implementation of the new siren system beyond the August 24, 2007 deadline. Entergy Nuclear Operations has been unable to meet these

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deadlines due to certain FEMA testing, review and operability requirements. FEMA has been authorized by the NRC to assess the new system and its readiness for full implementation. Further delays in implementation of the new siren system may subject Entergy Nuclear Operations, Inc. to additional fines in the future. The Indian Point Energy Center will continue to operate and maintain its existing siren emergency notification system until the new system is placed into service.

Legal Proceedings

We are involved in various claims and legal proceedings that occur from time to time in the ordinary course of business. We are not party to any pending legal proceedings that we believe could have a material adverse affect on our business, results of operations, financial condition or liquidity.

Employee Litigation

We are responding to lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsored plants. Entergy and we are responding to these suits and proceedings.

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MANAGEMENT

Executive Officers Following the Separation

While some of our expected executive officers are currently officers and employees of Entergy, upon the separation, none of these individuals will continue to be employees of Entergy. The following table sets forth information regarding individuals who are expected to serve as our executive officers following the separation.


Name	Age	Position

Richard J. Smith	56	Chief Executive Officer, Director
John R. McGaha	58	Chief Operating Officer

Richard J. Smith has over 30 years of experience in the electric utility industry and over 10 years of experience as an executive officer. In his current role, Mr. Smith serves as Entergy’s president and chief operating officer with responsibility for Entergy Nuclear and Entergy Operations, which includes fossil plant operations, transmission operations, system environmental and safety, system planning, compliance and performance management. From 2001 to 2007, Mr. Smith served as group president, Utility Operations of Entergy. Prior to joining Entergy, Mr. Smith served as president of Cinergy Resources, Inc., where he managed and directed Cinergy’s non-regulated retail gas supply business and also developed Cinergy’s non-regulated retail electric supply business in anticipation of retail open access in Ohio.

John R. McGaha has over 30 years of experience with Entergy’s nuclear program. Since February 2007, Mr. McGaha has served as president of planning, development and oversight for Entergy Nuclear Operations with responsibility for planning and innovation, business development and new plant activities and oversight. From 2000 to 2007, Mr. McGaha served as president of the Entergy Nuclear South business unit, with responsibility for Entergy’s five nuclear units in its retail electric service area. Mr. McGaha has five years of service with the U.S. Navy Nuclear Powered Submarine Program and retired from the U.S. Naval Reserve with the rank of Captain. Mr. McGaha also spent two and a half years designing coal-fired plants for Brown & Root.

Board of Directors Following the Separation

The following sets forth information with respect to those persons, in addition to Mr. Smith, who are expected to serve on our board of directors following the completion of the separation. The nominees will be presented to our sole shareholder, Entergy, for election prior to the separation. We intend to name and present additional nominees for election prior to the separation.


Name	Age	Position(s)

Committees

Effective upon the completion of the separation, our board of directors will have the following committees:

Compensation Committee Interlocks and Insider Participation

Each member of the Compensation Committee is an independent director. None of the Compensation Committee members has served as an officer of Enexus Energy, and none of Enexus Energy’s executive officers has served as a member of a compensation committee or board of directors of any other entity that has an executive officer serving as a member of Enexus Energy’s board of directors.

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COMPENSATION DISCUSSION AND ANALYSIS

Introduction

This Compensation Discussion and Analysis briefly discusses the philosophy and policies we apply to the compensation of our chief executive officer, or CEO, our yet to be named chief financial officer, or CFO, and our three other most highly compensated executive officers other than the CEO and CFO (collectively referred to as our “Named Executive Officers”) based on compensation from Entergy for 2007. You should read this information in combination with the more detailed compensation tables and other data presented elsewhere in this information statement.

The compensation of our Named Executive Officers for 2006 and 2007 was determined and paid by Entergy, and Entergy also determined and paid or will pay the compensation of our Named Executive Officers for the period in 2008 prior to the separation. Accordingly, the Compensation Discussion and Analysis that follows relates primarily to the compensation paid to our Named Executive Officers by Entergy for 2007. However, effective as of the separation and for subsequent years, our Personnel Committee will determine, and we will pay, the compensation of our Named Executive Officers. Please note that the principles and policies to be used by our Personnel Committee in determining such compensation have yet to be established. Accordingly, there is no assurance that the compensation of our Named Executive Officers following the separation will be the same as that prior to the separation, or that the same principles and policies used to determine compensation prior to the separation will be used to determine compensation following the separation.

Entergy has designed its compensation program to attract, retain, motivate and reward executives who can contribute to long-term success and thereby build value for shareholders. Entergy’s executive compensation package is comprised of a combination of short-term and long-term compensation elements. Short-term compensation includes base pay and annual cash incentive awards. Long-term compensation includes stock options and performance units.

The executive compensation program is approved by Entergy’s Personnel Committee, which is comprised entirely of independent board members. Unless otherwise indicated, the references in this Compensation Discussion and Analysis to the Personnel Committee or the Committee refer to the Entergy Personnel Committee.

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The following table summarizes the principal factors that Entergy takes into account in deciding the amount of each compensation element it pays or awards to executives:


Key Compensation Components
(where reported in summary
compensation table)		Factors

Base Salary (salary, column c)		- Company, business unit and individual performance - Market data - Internal pay equity - The Committee’s assessment of other elements of compensation

Performance Units (stock awards, column e)		- Compensation practices at peer group companies and in a broader group of utility companies - Target long-term compensation values in the market for similar jobs - The desire to ensure that a substantial portion of total compensation is performance-based - The Committee’s assessment of other elements of compensation

Stock Options (options, column f)		- Individual performance - Prevailing market practice - Targeted long-term value created by the use of stock options - Potential dilutive effect of stock option grants - The Committee’s assessment of other elements of compensation

Non-Equity Incentive Plan Compensation (Cash Bonus) (non-equity plan compensation, column g)		- Compensation practices at peer group companies and the general market for similar-size companies - Desire to ensure that a substantial portion of total compensation is performance-based - The Committee’s assessment of other elements of compensation

Entergy makes compensation decisions for the Named Executive Officers and each executive officer after taking into account all elements of the officer’s compensation. In making compensation decisions, Entergy applies the same compensation policies to the Named Executive Officers and all of its executive officers; however, the application of these policies results in different compensation amounts to individual officers because of: (i) differences in roles and responsibilities; (ii) differences in market-based compensation levels for specific officer positions; (iii) Entergy’s assessment of individual performance; and (iv) variations in business unit performance.

Compensation Program Administration

Role of Personnel Committee

The Personnel Committee has overall responsibility for approving the compensation program for Entergy’s named executive officers and makes all final decisions regarding Entergy’s named executive officers. The Personnel Committee is responsible for, among its other duties, the following actions related to Entergy’s named executive officers:


	•	reviewing and approving compensation policies and programs for the executive officers, including any employment agreement with an executive officer;

	•	evaluating the performance of Entergy’s Chairman and Chief Executive Officer; and

	•	reporting, at least annually, to the Entergy board of directors on succession planning, including succession planning for Entergy’s Chief Executive Officer.

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The Personnel Committee has authorized, in limited circumstances, the delegation of its authority to grant stock options under Entergy plans to Entergy’s Chairman and Chief Executive Officer and Senior Vice President of Human Resources and Administration subject to the following conditions:


	•	No grant may exceed an aggregate value of $1 million per grantee;

	•	All awards must be issued in accordance with the terms of Entergy’s plans, including the requirement that all options be issued for an exercise price not less than the fair market value of the stock on the date the option is granted;

	•	No awards may be granted to any executive officer of Entergy (as defined under Section 16 of the Exchange Act); and

	•	The Personnel Committee must be advised on at least a quarterly basis of the grants made under the exercise of this delegated authority.

As further described below, certain aspects of the compensation of officers who are not Entergy named executive officers, including Mr. McGaha, are not directly determined by the Personnel Committee. For instance, while the Committee does determine the number of performance units to be granted to Mr. McGaha, the Committee does not determine Mr. McGaha’s actual annual incentive target. Rather, the Committee establishes an overall available annual incentive pool for those officers, and the officers’ respective supervisors (in the case of Mr. McGaha, the chief executive of Entergy’s nuclear division, subject to the ultimate approval of Entergy’s Chief Executive Officer) establish the specific goal targets and ranges. Further, the chief executive of Entergy’s nuclear division and Entergy’s Chief Executive Officer have ultimate responsibility for adjusting Mr. McGaha’s salary as deemed appropriate. The chief executive of Entergy’s nuclear division and Entergy’s Chief Executive Officer also determine how many stock option awards are to be allocated to Mr. McGaha from an available pool established by the Personnel Committee for similarly situated officers, though the Personnel Committee ultimately approves the established allocations.

Role of the Compensation Consultant

In discharging its duties, the Personnel Committee has retained Towers Perrin as its independent compensation consultant to assist it, among other things, in evaluating different compensation programs and developing market data to assess the compensation programs. Under the terms of its engagement, Towers Perrin reports directly to the Personnel Committee, which has the right to retain or dismiss the consultant without the consent of the Entergy’s management. In addition, Towers Perrin is required to seek and receive the prior written consent of the Personnel Committee before accepting any material engagements from Entergy.

In considering the appointment of Towers Perrin, the Personnel Committee took into account that Towers Perrin provides from time to time general consulting services to Entergy’s management with respect to non-executive compensation matters. In this connection the Committee reviewed the fees and compensation received by Towers Perrin for these services over a historical period. After considering the nature and scope of these engagements and the fee arrangements involved, the Personnel Committee determined that the engagements did not create a conflict of interest. The Committee reviews on an ongoing basis the fees and compensation received by Towers Perrin for non-executive compensation matters on an annual basis to monitor its independence. Enexus Energy has not yet formed a compensation committee and has not yet determined whether it will retain a compensation consultant or, if it does, who that compensation consultant will be.

Role of Entergy’s Chief Executive Officer

The Personnel Committee solicits recommendations from Entergy’s Chief Executive Officer with respect to compensation decisions for Mr. Smith. Mr. Leonard’s role in this regard is limited to:


	•	providing the Committee with an assessment of the performance of Mr. Smith; and

	•	recommending base salary, annual merit increases, stock option and annual cash incentive plan compensation amounts for Mr. Smith.

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In addition, the Committee may request that Mr. Leonard provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in structure of bonus programs. Mr. Leonard does not play any role with respect to any matter affecting his own compensation nor does he have any role determining or recommending the amount, or form, of director compensation.

As noted above under “Role of Personnel Committee,” Mr. Leonard also plays a role in determining Mr. McGaha’s base salary, his annual incentive target and the number of stock options he receives.

Mr. Leonard may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. However, he is not in attendance at any meeting when the Committee determines and approves the compensation to be paid to Entergy’s named executive officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2007, Mr. Leonard attended six meetings of the Personnel Committee.

In 2007, the Committee’s compensation consultant met at the request of the Personnel Committee with Mr. Leonard to review market trends in executive and management compensation and to discuss Entergy’s overall compensation philosophy, such as the optimum balance between base and incentive compensation. In addition, the Committee requested that its independent compensation consultant interview Mr. Leonard to obtain management feedback on the impact of compensation programs on employees and information regarding the roles and responsibilities of Entergy’s named executive officers.

Objectives of the Executive Compensation Program


	•	The greatest part of the compensation of a Named Executive Officer should be in the form of “at risk,” performance-based compensation.

Entergy has designed its compensation programs to ensure that a significant percentage of the total compensation of the named executive officers is contingent on achievement of performance goals that drive total shareholder return and result in increases in common stock price. For example, each annual cash incentive and long-term performance unit program is designed to pay out only if Entergy achieves pre-established performance goals. Assuming achievement of these performance goals at target level, approximately 80% of the annual target total compensation (excluding non-qualified supplemental retirement income) of Entergy’s Chief Executive Officer is represented by performance-based compensation and the remaining 20% is represented by base salary. For Mr. Smith, assuming achievement of performance goals at the target levels, approximately 65% of his annual target total compensation (excluding non-qualified supplemental retirement income) is represented by performance-based compensation and the remaining 35% by base salary; for Mr. McGaha, 60% of his annual target total compensation (excluding non-qualified supplemental retirement income) is represented by performance-based compensation and the remaining 40% by base salary. Entergy’s Chief Executive Officer’s total compensation is at greater risk than that of our named executive officers, reflecting both market practice and acknowledging the leadership role of the Entergy Chief Executive Officer in setting Entergy policy and strategies.


	•	A substantial portion of Named Executive Officers’ compensation should be delivered in the form of equity awards.

To align the economic interests of the named executive officers with shareholders, Entergy believes that a substantial portion of their total compensation should be in the form of equity-based awards. Equity awards are typically granted in the form of stock options with a three-year vesting schedule and performance units with a three-year performance cycle. Stock options are generally subject only to time-based vesting. Performance units pay out only if Entergy achieves specified performance targets. The amount of payout varies based on the level of performance achieved.


	•	Entergy’s compensation programs should enable it to attract, retain and motivate executive talent by offering compensation packages that are competitive but fair.

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It is in the best interests of Entergy’s shareholders’ that Entergy attract and retain talented executives by offering compensation packages that are competitive but fair. Entergy’s Personnel Committee has sought to develop compensation programs that deliver total target compensation in the aggregate at approximately the 50th percentile of the market.

The Starting Point

To develop a competitive compensation program, Entergy’s Personnel Committee on an annual basis reviews base salary and other compensation data from two sources:


	•	Survey Data: The Committee uses published and private compensation survey data to develop marketplace compensation levels for executive officers. The data, which is compiled by the Committee’s independent compensation consultant, compares the current compensation levels received by each executive officer against the compensation levels received by executives holding similar positions at companies with corporate revenues consistent with Entergy’s revenues. For non-industry specific positions such as a chief financial officer, the Committee reviews data from general industry. For management positions that are industry-specific, the Committee reviews data from energy service companies. The survey data reviewed by the Committee covers approximately 300 public and private companies in general industry and approximately 60 to 70 public and private companies in the energy services sector. In benchmarking compensation levels against the survey data, the Committee considers only the aggregated survey data. The identity of the companies comprising the survey data is not disclosed to, or considered by, the Committee in its decision-making process and, thus, is not considered material by the Committee. The Committee uses the survey data to develop compensation programs that deliver total target compensation at approximately the 50^th percentile of the market. For this purpose, the Committee reviews the results of the survey data (organized in tabular format) comparing compensation relative to the 25^th, 50^th (or median) and 75^th percentile of the market. The Committee considers its objectives to have been met if Entergy’s Chief Executive Officer and the executive officers who constitute what Entergy refers to as its “Office of the Chief Executive,” considered as a group (nine officers, including Mr. Smith, but not any other Named Executive Officer), have a target compensation package that falls within the range of 90 – 110% of the 50^th percentile benchmarked in the survey data. Actual compensation received by an individual officer may be above or below the 50^th percentile based on an individual officer’s skills, performance and responsibilities.

	•	Proxy Analysis: As an additional point of analysis, the Committee reviews data derived from proxy statements comparing compensation levels against the compensation levels of the corresponding executive officers from eighteen of the companies included in the Philadelphia Utilities Index. Unlike the survey data (which is used as the primary data for purposes of benchmarking compensation), the market data from the proxy analysis are not comparable to Entergy in terms of roles and responsibilities. Rather, the market data from the proxy analysis are compared to Entergy’s executive officers based on pay rank. These companies are:


• AES Corporation		• Exelon Corporation
• Ameren Corporation		• FirstEnergy Corporation
• American Electric Power Co. Inc.		• FPL Group Inc.
• CenterPoint Energy Inc.		• Northeast Utilities
• Consolidated Edison Inc.		• PG&E Corporation
• Dominion Resources Inc.		• Progress Energy, Inc.
• DTE Energy Company		• Public Service Enterprise Group, Inc.
• Duke Energy Corporation		• Southern Company
• Edison International		• XCEL Energy

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Elements of the Compensation Program

The major components of Entergy’s executive compensation program are presented below.

Short-Term Compensation

Base Salary

Base salary is a component of the named executive officers’ compensation package because the Committee believes it is appropriate that some portion of the compensation that is provided to these officers be provided in a form that is a fixed cash amount. Also, base salary remains the most common form of payment throughout all industries. Its use ensures a competitive compensation package to the Named Executive Officers.

The Committee (in the case of Mr. Smith) or certain senior Entergy officers (in the case of the other Named Executive Officers) determine whether to award named executive officers annual merit increases in base salary based on the following factors:


	•	Company, business unit and individual performance during the prior year;

	•	Market data;

	•	Internal pay equity; and

	•	An assessment of other elements of compensation provided to the named executive officer.

The corporate and business unit goals and objectives vary by individual officers and include, among other things, corporate and business unit financial performance, capital expenditures, cost containment, safety, reliability, customer service, business development and regulatory matters.

Entergy’s use of “internal pay equity” in setting merit increases is limited to determining whether a change in an officer’s role and responsibilities relative to other officers requires an adjustment in the officer’s salary. There is no predetermined formula against which the base salary of one named executive officer is measured against another officer or employee.

In 2007, on the basis of the market data and other factors described above, Mr. Smith received a merit-based salary increase of 3.5%. In February 2007, Mr. McGaha was awarded an 8.6% base salary adjustment to reflect his increased responsibility as a result of Entergy’s nuclear alignment. In general these increases were consistent with the increase percentages approved with respect to Entergy named executive officers in the last two years (excluding adjustments in salaries related to market factors, promotions or other changes in job responsibilities). In addition, Mr. Smith received a salary increase of approximately 11% upon his promotion to President and Chief Operating Officer of Entergy in April 2007 to reflect the increased responsibilities of his new position and comparative market data for officers holding similar positions and performing similar responsibilities, and Mr. McGaha received a salary increase of approximately 4.7% in December 2007 as part of a market adjustment for leaders of Entergy’s nuclear division.

Non-Equity Incentive Plans (Cash Bonus)

Entergy includes performance-based incentives in the named executive officers’ compensation packages because it encourages the named executive officers to pursue objectives consistent with the overall goals and strategic direction that the Entergy board has set for Entergy. Annual incentive plans are commonly used by companies in a variety of industry sectors to compensate their executive officers.

The named executive officers participate in a performance-based cash incentive plan known as the Executive Annual Incentive Plan, or Annual Incentive Plan. The plan operates on a calendar year basis. Entergy uses a performance metric known as the Entergy Achievement Multiplier to determine the payouts for each particular calendar year. The Entergy Achievement Multiplier is used to determine the percentage of target annual plan awards that will be paid each year to each named executive officer. In December 2006,

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Entergy selected the Entergy Achievement Multiplier for 2007 awards to be based in equal part on earnings per share and operating cash flow. The Committee selected these performance measures because:


	•	earnings per share and operating cash flow have both a correlative and causal relationship to shareholder value performance;

	•	earnings per share and operating cash flow targets are aligned with externally-communicated goals; and

	•	earnings per share and operating cash flow results are readily available in earning releases and SEC filings.

In addition, these measures are commonly used by other companies, including Entergy’s industry peer group companies, as components of their incentive programs. For example, approximately two-thirds of the industry peer group companies use earnings per share as an incentive measure and one-third use some type of cash flow measure. The Personnel Committee evaluates the performance measures used for the Annual Incentive Plan on an annual basis.

The Committee sets minimum and maximum achievement levels under the Annual Incentive Plan at approximately 10% below and 10% above target achievement levels. Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight line interpolation. In general, the Committee seeks to establish target achievement levels such that the relative difficulty of achieving the target level is consistent from year to year. Over the past five years ending in 2007, the average Entergy Achievement Multiplier, representing earnings per share and operating cash flow results, was 135% of target. This result reflects the strong performance of Entergy during this period.

In December 2006, the Committee set the 2007 target award for incentives to be paid in 2008 under the Annual Incentive Plan for our Chief Executive Officer at 70% of his base salary. In setting this target award, the Personnel Committee considered several factors, including:


	•	analysis provided by the Committee’s independent compensation consultant as to compensation practices at the industry peer group companies and the general market for similar-size companies;

	•	competitiveness of Entergy’s compensation plans and their ability to attract and retain top executive talent;

	•	the individual performance of Mr. Smith;

	•	target bonus levels in the market for comparable positions;

	•	the desire to ensure that a substantial portion of total compensation is performance-based;

	•	the relative importance, in any given year, of the short-term performance goals established pursuant to the Annual Incentive Plan;

	•	the Committee’s assessment of other elements of compensation provided to Mr. Smith; and

	•	the recommendation of Entergy’s Chief Executive Officer, including his assessment of Mr. Smith’s performance.

The target award for Mr. McGaha was set by his supervisor, the chief executive of Entergy’s nuclear division (subject to ultimate approval of Entergy’s Chief Executive Officer), who allocated a potential incentive pool established by the Personnel Committee among various of his direct and indirect reports. In setting the target award for Mr. McGaha, the supervisor took into account considerations similar to those considered by the Personnel Committee in establishing Mr. Smith’s incentive target.

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In January 2008, the Committee determined the Entergy Achievement Multiplier to be used for purposes of determining annual incentives for 2007. The targets established to measure management performance against as reported results were:


	Minimum		Target		Maximum
Earnings Per Share ($)		4.77		5.30		5.83
Operating Cash Flow ($ billion)		2.3		2.6		2.9

After reviewing earnings per share and operating cash flow results against the performance objectives in the above table, the Personnel Committee certified the Entergy Achievement Multiplier at 123% of target.

Under the terms of the program, the Entergy Achievement Multiplier is automatically increased by 25% for the members of Entergy’s Office of the Chief Executive (including Mr. Smith but not any of the other Named Executive Officers), subject to the Personnel Committee’s discretion to adjust the automatic multiplier downward or eliminate it altogether. The multiplier, which Entergy refers to as the Management Effectiveness Factor, is intended to provide the Committee, through the exercise of negative discretion, a mechanism to take into consideration specific achievement factors relating to the overall performance of Entergy. In January 2008, the Committee exercised its negative discretion to eliminate the Management Effectiveness Factor, reflecting the Personnel Committee’s determination that the Entergy Achievement Multiplier, in and of itself without the Management Effectiveness Factor, was consistent with the performance levels achieved by Entergy’s management.

The following table shows the Annual Incentive Plan payments as a percentage of base salary for 2007 based on an Entergy Achievement Multiplier of 123%:


Named Executive
Officer	Target		Percentage Base Salary
Richard J. Smith		70%		86%
John R. McGaha		60%		74%

The amounts paid for 2007 under the Annual Incentive Plan for the Named Executive Officers are disclosed in column (g) of the Summary Compensation Table located on page 121.

Nuclear Retention Plan

Some of Entergy’s executives, including Mr. McGaha but not any of the other Named Executive Officers, participate in a special retention plan for officers and other leaders with special expertise in the nuclear industry. Entergy established the plan to attract and retain management talent in the nuclear power field, a field which requires unique technical and other expertise that is in great demand in the utility industry. For individuals who commenced participation on or after January 1, 2007, like Mr. McGaha, the plan covers a three-year period. For example, an individual who commenced participation on February 15, 2007, subject to his or her continued employment with a participating company, is eligible to receive a special cash bonus consisting of three payments, each consisting of an amount from 15% to 30% of such participant’s then (2007) base salary on February 15 of each of 2008, 2009 and 2010.

Long-Term Compensation

Entergy’s long-term equity incentive programs are intended to reward Named Executive Officers for achievement of shareholder value creation over the long-term. In its long-term incentive programs, Entergy primarily uses a mix of performance units and stock options in order to accomplish different objectives. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock appreciation and dividend payments relative to industry peer group companies. Options provide a direct incentive for growing the price of Entergy’s common stock. In addition, Entergy occasionally awards restricted units for retention purposes or to offset forfeited compensation in order to attract officers and managers from other companies.

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Each of the performance units and stock options granted to the Named Executive Officers in 2007 was awarded under Entergy’s 2007 Equity Ownership and Long Term Cash Incentive Plan, which Entergy refers to as the 2007 Equity Ownership Plan.

Performance Unit Program

Entergy issues performance unit awards to the Named Executive Officers under the Performance Unit Program. Each Performance Unit equals the cash value of one share of Entergy common stock at the end of the performance cycle. Each unit also earns the cash equivalent of the dividends paid during the three-year performance cycle. The Performance Unit Program is structured to reward Named Executive Officers only if performance goals set by the Personnel Committee are met. The Personnel Committee has no discretion to authorize awards if minimum performance goals are not achieved. The Performance Unit Program provides a minimum, target and maximum achievement level. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of its industry peer group companies. The Personnel Committee chose total shareholder return as a measure of performance because it assesses Entergy’s creation of shareholder value relative to other electric utilities over the performance cycle. Minimum, target and maximum performance levels are determined by reference to the quartile ranking of Entergy’s total shareholder return against the total shareholder return of industry peer group companies.

Prior to 2006, this peer group was the Standard & Poor’s Electric Utility Index. Beginning with the 2006-2008 performance period, the Personnel Committee identified the Philadelphia Utility Index as the industry peer group for total shareholder return performance because the companies represented in this index more closely approximate Entergy in terms of size and scale and because the companies comprising the Standard and Poor’s Electric Utility Index had been reduced by 50%, which resulted in a pool of companies insufficient for comparative purposes. The companies included in the Philadelphia Utility Index are provided on page 110.

Subject to achievement of the Performance Unit Program performance levels, the Personnel Committee established a target amount of 3,900 performance units for Mr. Smith for the 2008–2010 performance cycle. The target amount for Mr. McGaha was 1,400 units. The range of payouts under the program is shown below.

Quartiles:

Performance

Zero

Minimum

Target

Maximum

Levels:

Total Shareholder
Return Ranges:

25^th percentile and below

25^th to 50^thpercentiles

50^th to 75^thpercentiles

75^th percentile and
above

Payouts:

No Payout

Interpolate
between Minimum
and Target
(10% to 100% of Target)

Interpolate
between Target
and Maximum
(100% to 250% of Target)

Maximum Payout (250% of Target)

The Personnel Committee sets payout opportunities for the Performance Unit Program each year. In determining payout opportunities, the Committee considers several factors, including:


	•	the advice of the Committee’s independent compensation consultant regarding compensation practices at Entergy’s industry peer group companies;

	•	competitiveness of Entergy’s compensation plans and their ability to attract and retain top executive talent;

	•	target long-term compensation values in the market for similar jobs;

	•	the desire to ensure, as described above, that a substantial portion of total compensation is performance-based;

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	•	the relative importance, in any given year, of the long-term performance goals established pursuant to the Performance Unit Program; and

	•	the Committee’s assessment of other elements of compensation provided to the named executive officer.

For the 2005-2007 performance cycle, the target amount established for our Chief Executive Officer was 6,000 performance units and for the other named executive officers, the target amounts established were 2,700 performance units. Participants could earn performance units consistent with the range of payouts as described above for the 2008-2010 performance cycle.

In January 2008, the Committee assessed Entergy’s total shareholder return for the 2005-2007 performance period and determined the actual number of performance units to be paid to Performance Unit Program participants for the 2005-2007 performance cycle. Performance was measured in a manner similar to that described above for the 2008-2010 cycle, on the basis of relative total shareholder return.

For purposes of determining Entergy’s relative performance for the 2005-2007 period, the Committee used the Standard and Poor’s Electric Utility Index as Entergy’s peer group. Based on market data provided by Entergy’s independent compensation consultant and the recommendation of management, the Committee compared Entergy’s total shareholder return against the total shareholder return of the companies that comprised the Standard and Poor’s Electric Utility Index at the beginning of the plan period. Because TXU was delisted during the plan period due to a private buyout and its return could not be objectively measured, however, TXU was excluded from the peer group.

Based on a comparison of Entergy’s performance relative to the Standard & Poor’s Electric Utility Index as described above, the Committee concluded that Entergy had exceeded the performance targets for the 2005-2007 performance cycle, resulting in a payment of 225% of target. Each performance unit was then automatically converted into cash at the rate of $119.52 per unit, the closing price of Entergy’s common stock on the last trading day of the performance cycle (December 31, 2007), plus dividend equivalents accrued over the three-year performance cycle. See the 2007 Stock Option Exercises and Stock Vested table for the amount paid to each of the Named Executive Officers for the 2005-2007 performance unit cycle.

Stock Options

The Personnel Committee (and, in the case of Mr. McGaha, the chief executive of Entergy’s nuclear division and Entergy’s Chief Executive Officer as well) considered several factors in determining the amount of stock options it granted under Entergy’s equity ownership plans to the named executive officers, including:


	•	individual performance;

	•	prevailing market practice in stock option grants;

	•	the targeted long-term value created by the use of stock options;

	•	the number of participants eligible for stock options, and the resulting “burn rate” (i.e., the number of stock options authorized divided by the total number of shares outstanding) to assess the potential dilutive effect; and

	•	the Committee’s assessment of other elements of compensation provided to the named executive officer.

For stock option awards to Mr. Smith, the Committee’s assessment of his individual performance, done in consultation with Entergy’s Chief Executive Officer, is the most important factor in determining the number of options awarded.

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The following table sets forth the number of stock options granted to each named executive officer in 2007. The exercise price for each option was $91.82, which was the closing fair market value of Entergy Corporation common stock on the date of grant.


Named Executive Officer			Stock Options
Richard J. Smith			60,000
John R. McGaha			16,500

For additional information regarding stock options awarded in 2007 to each of the named executive officers, see the 2007 Grants of Plan-Based Awards table.

Under Entergy’s equity ownership plans, all options must have an exercise price equal to the closing fair market value of Entergy common stock on the date of grant. In addition, Entergy has adopted a policy requiring that, if a named executive officer (as well as certain other officers) exercises any stock option granted on or after January 1, 2003, the officer must retain at least 75% of the after-tax net profit from such stock option exercise in the form of Entergy common stock until the earlier of 60 months from the date on which the option is exercised or the termination of the officer’s full-time employment.

Entergy has not adopted a formal policy regarding the granting of options at times when it is in possession of material non-public information. However, Entergy generally grants options to named executive officers only during the month of January in connection with its annual executive compensation decisions. On occasion, Entergy may grant options to newly hired employees or existing employees for retention or other limited purposes.

Restricted Units

Restricted units granted under Entergy’s equity ownership plans represent phantom shares of Entergy common stock (i.e., non-stock interests that have an economic value equivalent to a share of Entergy common stock). Entergy occasionally grants restricted units to employees for retention purposes or to offset forfeited compensation from a previous employer or to existing employees for retention or other limited purposes. If all conditions of the grant are satisfied, restrictions on the restricted units lift at the end of the restricted period, and a cash equivalent value of the restricted units is paid. The settlement price is equal to the number of restricted units multiplied by the closing price of Entergy common stock on the date restrictions lift. Restricted units are not entitled to dividends or voting rights. Restricted units are generally time-based awards for which restrictions lift, subject to continued employment, over a two- to five-year period.

No named executive officers received restricted units from Entergy during 2007.

Benefits, Perquisites, Agreements and Post-Termination Plans

Pension Plan, Pension Equalization Plan, System Executive Retirement Plan and Supplemental Retirement Plan

The Named Executive Officers participate in an Entergy-sponsored pension plan that covers a broad group of employees. This pension plan is a funded, tax-qualified, noncontributory defined benefit pension plan. Benefits under the pension plan are based upon an employee’s years of service with Entergy and the employee’s average monthly rate of earnings (which generally includes salary and eligible bonus, other than Annual Incentive Plan bonus) for the highest consecutive 60 months during the 120 months preceding termination of employment or “Eligible Earnings,” and are payable monthly after separation from Entergy. The amount of annual earnings that may be considered in calculating benefits under the pension plan is limited by federal law.

Benefits under the pension plan are calculated as an annuity equal to 1.5% of a participant’s Eligible Earnings multiplied by years of service. Years of service under the pension plan formula cannot exceed 40. Contributions to the pension plan are made entirely by Entergy and are paid into a trust fund from which the benefits of participants will be paid.

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Entergy sponsors a Pension Equalization Plan, which is available to a select group of management and highly compensated employees, including the Named Executive Officers. The Pension Equalization Plan is a non-qualified unfunded plan that provides from Entergy’s general assets an amount substantially equal to the difference between the amount that would have been payable under the pension plan, but for legislation limiting pension benefits and earnings that may be considered in calculating pension benefits, and the amount actually payable under the pension plan. The Pension Equalization Plan also takes into account as earnings any Annual Incentive Plan incentive awards.

Entergy also sponsors a System Executive Retirement Plan available to approximately 60 officers, including the Named Executive Officers. Participation in the System Executive Retirement Plan requires individual approval by the plan administrator. The System Executive Retirement Plan is designed to offer a replacement income ratio in the range (based on management level and total years of service) of 55% to 65% of a Named Executive Officer’s final three-year average annual compensation (i.e., generally one-third of the sum of the participant’s base salary and Annual Incentive Plan bonus for the three years during the last 10 years preceding termination of employment in which such sum is the highest). The System Executive Retirement Plan recognizes a maximum of 30 years of service for purposes of calculating a participant’s benefit. Amounts payable under the System Executive Retirement Plan benefit are offset by the value of the Pension Plan and Pension Equalization Plan benefits, and are also typically offset by any prior employer pension benefit available to the executive. While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.


Years of Service			Executives at Management Level 3 & above – includes the Named Executive Officers (Percent of Final Three-Year Average Annual Compensation)
20 Years			50.0%
30 years			60.0%

Finally, Entergy also sponsors a Supplemental Retirement Plan in which various executives participate, including Mr. McGaha but no other Named Executive Officers. Under that plan, after attaining a minimum age of 55 and 10 or more years of service, a participant is entitled to a monthly benefit equal to .0833 times the sum of: 1.25% of the participant’s average basic annual salary for each of the first 10 years of service, 1% of the participant’s average basic annual salary for each year of service after 10 and not more than 20 years of service, and 0.75% of the participant’s average basic annual salary for each year of service in excess of 20 years of service, provided that in no event will the monthly benefit exceed 2.5% of the participant’s average basic annual salary, nor will such monthly benefits be payable for more than 120 months. Average basic annual salary generally means the average of the basic annual salary for the highest consecutive five years of service during the 10 years immediately preceding the earlier of the participant’s death, retirement or other separation from service, and basic annual salary generally means a participant’s regular annual cash earnings from all Entergy companies, exclusive of overtime or other special payments, but including any and all bonuses or other incentive compensation paid pursuant to the terms of the Annual Incentive Plan, but excluding certain amounts for years before 1995. Certain participants are eligible for a lump-sum payment in lieu of monthly installment payments. The Supplemental Retirement Plan benefit is not vested until age 65. Subject to the approval of the Entergy employer, an employee who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the benefit beginning as early as age 55 with 10 years of service. Benefits payable prior to age 65 may be subject to certain reductions if the participant has less than 10 years of service.

The Committee believes that the Pension Plan, Pension Equalization Plan, System Executive Retirement Plan and Supplemental Retirement Plan are an important part of Entergy’s Named Executive Officers’ compensation program. These plans are important in the recruitment of top talent in the competitive market, as these types of supplemental plans are typically found in companies of similar size to Entergy. These plans serve a critically important role in the retention of Entergy’s senior executives, as benefits from these plans increase for each year that these executives remain employed by Entergy. The plans thereby encourage

117

Entergy’s most senior executives to remain employed by Entergy and continue their work on behalf of Entergy shareholders.

Entergy has agreed to provide extra service credit to Mr. Smith under the Pension Equalization Plan and Supplemental Executive Retirement Plan. Entergy typically offers these service credit benefits as one element of the total compensation package offered to new mid-level or senior executives that it recruits from other companies. By offering executives “credited service,” Entergy is able to compete more effectively to hire these employees by mitigating the potential loss of their pension benefits resulting from accepting employment with Entergy. Mr. McGaha has not been credited with any extra years of credited service under any of the foregoing plans.

See the Pension Benefits table for additional information regarding benefits under the plans described under this caption.

Savings Plan

The Named Executive Officers are eligible to participate in an Entergy-sponsored Savings Plan that covers a broad group of employees. This is a tax-qualified retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary up to certain contribution limits defined by law. In addition, under the Savings Plan, Entergy matches an amount equal to seventy cents for each dollar contributed by eligible employees, including the Named Executive Officers, on the first 6% of their earnings for that pay period. Entergy maintains the Savings Plan for its employees, including its Named Executive Officers, because Entergy wishes to encourage its employees to save some percentage of their cash compensation for their eventual retirement. The Savings Plan permits employees to make such savings in a manner that is relatively tax efficient. This type of savings plan is also a critical element in attracting and retaining talent in a competitive market.

Health & Welfare Benefits

The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include medical, dental and vision coverage, life and accidental death & dismemberment insurance and long-term disability insurance. Eligibility, coverage levels, potential employee contributions and other plan design features are the same for the Named Executive Officers as for the broad employee population.

Executive Long-Term Disability Program

All of Entergy’s executive officers, as well as all of the Named Executive Officers, are eligible to participate in the Executive Long-Term Disability program. Individuals who elect to participate in this plan will receive upon the occurrence of a long-term disability 65% of the difference between their base salary and the approximate $275,000 cap on disability payments under Entergy’s general long-term disability plan.

Executive Deferred Compensation

The Named Executive Officers are eligible to defer up to 100% of the following payments (less applicable deductions and withholdings) into the Entergy-sponsored Executive Deferred Compensation Plan:


	•	Base Salary

	•	Annual Incentive Plan Bonus

	•	Performance Unit Program Awards

The Named Executive Officers also are eligible to defer up to 100% of the following payments (less applicable deductions and withholdings) into Entergy’s 2007 Equity Ownership Plan:


	•	Annual Incentive Plan Bonus

	•	Performance Unit Program Awards

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Additionally, the Named Executive Officers also have deferred account balances under a frozen defined contribution restoration plan. Amounts deferred under the Executive Deferred Compensation Plan and 2007 Equity Ownership Plan are subject to limitations prescribed by law and the respective plan.

All deferral amounts represent an unfunded liability of the employer. Amounts deferred into the 2007 Equity Ownership Plan are deemed invested in phantom shares of Entergy common stock. Amounts deferred under the Executive Deferred Compensation Plan are deemed invested in one or more of the investment options (generally mutual funds) offered under the Savings Plan. Within the Executive Deferred Compensation Plan, a Named Executive Officer may move funds from one deemed investment option to another. Except for deferrals not subject to Section 409A of the Code, the Named Executive Officer does not have the ability to withdraw funds, except within the terms provided in such officer’s deferral election.

Entergy does not “match” amounts that are deferred by employees pursuant to the Executive Deferred Compensation Plan or 2007 Equity Ownership Plan. With the exception of allowing for the deferral of federal and state taxes, Entergy provides no additional benefit to the Named Executive Officer for deferring any of the above payments. Any increase in value of the deferred amounts results solely from the increase in value of the investment option selected (Entergy stock or mutual fund). Deferred amounts are credited with earnings or losses based on the rate of return of deemed investment options or Entergy common stock, as selected by the participants.

Entergy provides this benefit because the Committee believes it is standard market practice to permit officers to defer the cash portion of their compensation. The Executive Deferred Compensation Plan and 2007 Equity Ownership Plan permit them to do this while also receiving gains or losses on deemed investments, as described above. Entergy believes that provision of this benefit is important as a retention and recruitment tool as many, if not all, of the companies with which it competes for executive talent provide a similar arrangement to their senior employees.

Perquisites

Entergy provides the Named Executive Officers with certain perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. However, perquisites are not a material part of the compensation program. In 2007, Entergy offered the Named Executive Officers limited benefits such as the following: corporate aircraft usage, personal financial counseling, annual physical exams (which are mandatory for Entergy’s named executive officers) and club dues. The Named Executive Officers may use corporate aircraft for personal travel subject to the approval of Entergy’s Chief Executive Officer. The Personnel Committee reviews all perquisites, including the use of corporate aircraft, on an annual basis. For additional information regarding perquisites, see the “All Other Compensation” column in the Summary Compensation table.

Retention Agreements and other Compensation Arrangements

The Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly all of the companies with which Entergy competes for executive talent have similar arrangements in place for their senior employees.

To achieve these objectives, Entergy has established a System Executive Continuity Plan under which each of the Named Executive Officers is entitled to receive “change of control” payments and benefits if such officer’s employment is involuntarily terminated for similar qualifying events or circumstances. Based on the market data provided by its independent compensation consultant, the Committee believes the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices.

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In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for that officer. Entergy has voluntarily adopted a policy that any severance arrangements providing benefits in excess of 2.99 times an officer’s annual base salary and bonus must be approved by Entergy’s shareholders.

On July 26, 2007, our Chief Executive Officer agreed to terminate his retention agreement with Entergy. Upon termination of the agreement, Mr. Smith was reinstated in Entergy’s System Executive Continuity Plan. Reinstatement in the System Executive Continuity Plan generally aligned Mr. Smith’s change of control arrangements with those of Entergy’s other executive officers. Mr. Smith voluntarily elected to limit his cash payment under the System Executive Continuity Plan to the 2.99 cap, which is lower than the cash payment level he is entitled to under the System Executive Continuity Plan, since his original participation occurred prior to the date when the 2.99 cap was implemented.

Mr. McGaha participates in the System Executive Continuity Plan, but he is not a party to any individual retention or other employment agreement with Entergy.

Tax and Financial Accounting Considerations

Section 162(m) of the Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to a chief executive officer or any other of its three other most highly compensated executive officers (other than the chief financial officer), unless that compensation is “performance-based compensation” within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to Entergy’s named executive officers. However, the Personnel Committee and the Entergy board of directors believe that it is in the best interest of Entergy that the Personnel Committee retain the flexibility and discretion to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee as well as other corporate goals that the Committee deems important to Entergy’s success, such as encouraging employee retention and rewarding achievement. Our Personnel Committee has not established a policy regarding the effect of tax considerations on the determination of executive compensation.

Likewise, the Entergy Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to Entergy’s named executive officers. However, the Personnel Committee and the Entergy board of directors believe that it is in the best interest of Entergy that the Personnel Committee retain the flexibility and discretion to make compensation awards regardless of their financial accounting consequences. Our Personnel Committee has not established a policy regarding the effect of financial accounting considerations on the determination of executive compensation.

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EXECUTIVE COMPENSATION

Set forth below is information concerning compensation paid to or earned by each of our Named Executive Officers for services in all capacities to Entergy with regard to the specified periods. All references to any equity-based awards, including stock options, performance units and restricted units, relate to awards granted by Entergy in regard to Entergy common stock.

Summary Compensation Table

The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal years ended December 31, 2007 and 2006. For information on the principal positions held by each of the Named Executive Officers, see “Management—Executive Officers Following the Separation.” The compensation set forth in the table represents the aggregate compensation paid by all Entergy companies. None of the Entergy companies has entered into any employment agreements with any of the Named Executive Officers (other than the change in control arrangement described in “Potential Payments upon Termination or Change in Control” below). For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”

Change in

Pension

Value and

Non-Equity

Nonqualified

Incentive

Deferred

All

Stock

Option

Plan

Compensation

Other

Name and

Awards

Compensation

Earnings

Compensation

Principal

Salary

Bonus

($)

Total

Position

Year

($)

⁽¹⁾

⁽²⁾

⁽³⁾

⁽⁴⁾

⁽⁵⁾

($)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

Richard J.

2007

$599,612

$ -

$1,809,008

$590,666

$535,886

$743,700

$60,627

$4,339,499

Smith

Chief

2006

$536,650

$ -

$1,084,755

$414,959

$718,918

$183,800

$67,338

$3,006,420

Executive

Officer

John R.

2007

$376,806

$ -

$769,915

$205,204

$295,200

$1,173,400

$44,870

$2,865,395

McGaha

Chief

2006

$348,485

$ -

$500,677

$168,638

$421,988

$264,500

$31,066

$1,735,354

Operating
Officer


(1)		The amounts in column (e) represent the dollar amount recognized for financial statement reporting purposes in accordance with Financial Accounting Standards Board Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment (which is referred to as “SFAS l23R”) of performance units granted under the Performance Unit Program. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the Financial Statements in Entergy’s Form 10-K for the year ended December 31, 2007.

(2)		The amounts in column (f) represent the dollar amount recognized for financial statement reporting purposes in accordance with SFAS l23R of stock options. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the Financial Statements in Entergy’s Form 10-K for the year ended December 31, 2007.

(3)		The amounts in column (g) represent cash payments made under the Annual Incentive Plan.

(4)		The amounts in column (h) include the annual actuarial increase in the present value of the Named Executive Officer’s benefits under all pension plans established by Entergy using interest rate and mortality rate assumptions consistent with those used in Entergy’s financial statements and includes amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested. None of the increase is attributable to above-market or preferential earnings on nonqualified deferred compensation (see “2007 Nonqualified Deferred Compensation”).

(5)		The amounts set forth in column (i) for 2007 include (a) matching contributions by Entergy to each of the Named Executive Officers; (b) life insurance premiums; (c) tax gross up payments, and (d) perquisites and other personal benefits. The amounts are listed in the following table:

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	Richard		John R.
	J. Smith		McGaha

Company Contribution
- Savings Plan		$9,450		$9,450
Life Insurance Premium		$2,855		$1,691
Tax Gross Up Payments		$15,306		$8,379
Perquisites and Other Compensation		$33,016		$25,350


Total		$60,627		$44,870

Perquisites and Other Personal Benefits

The amounts set forth in column (i) also include perquisites and other personal benefits that Entergy provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites and other personal benefits were provided by Entergy in 2007 to the Named Executive Officers:

Named Executive

Financial

Personal Use of

Executive

Officer

Counseling

Corporate Aircraft

Physicals

Richard J. Smith

John R. McGaha

None of the individual perquisites items exceeded $25,000 for any of the Named Executive Officers.

2007 Grants of Plan-Based Awards

The following table summarizes award grants during 2007 to our Named Executive Officers.

All

All Other

Other

Option

Grant

Stock

Awards:

Date

Awards:

Number

Fair

Number

Exercise

Value of

Estimated Future Payouts Under

Estimated Future Payouts

Securities

or Base

Stock

Non-Equity Incentive Plan

under Equity Incentive Plan

Shares

Under-

Price of

and

Awards⁽¹⁾

Awards⁽²⁾

of Stock

lying

Option

Grant

Threshold

Target

Maximum

Threshold

Target

Maximum

or Units

Options

Awards

Name

Date

($)

(#)

(#)⁽³⁾

($/Sh)

($)

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

Richard

1/25/07

435,680

871,360

J. Smith

1/25/07

450

4,500

11,250

413,190

1/25/07

60,000

91.82

943,500

John R.

1/25/07

240,000

480,000

McGaha

1/25/07

210

2,100

5,250

192,822

1/25/07

16,500

91.82

259,463

(1) The amounts in columns (c), (d) and (e) represent minimum, target and maximum payment levels under the Annual Incentive Plan. The actual amounts awarded are reported in column (g) of the Summary Compensation Table.

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2007 Outstanding Equity Awards at Fiscal Year-End

The following table summarizes unexercised options, stock that has not vested and equity incentive plan awards for each Named Executive Officer outstanding as of the end of 2007.

Option Awards

Stock Awards

(j)

Equity

(i)

Incentive

(d)

Equity

Plan

Equity

Incentive

Awards:

Incentive

Plan

Market or

Plan

Awards:

Payout

(b)

(c)

Awards:

(g)

(h)

Number of

Value of

Number

Market

Unearned

of Shares

Value of

Shares,

Securities

or Units

Shares or

Units or

Underlying

(e)

of Stock

Units of

Other

Unexercised

Option

(f)

That Have

Stock

Rights

Options

Unearned

Exercise

Option

Not

That Have

(a)

(#)

Options

Price

Expiration

Vested

Not Vested

Name

Exercisable

Unexercisable

(#)

($)

Date

(#)

($)

(#)

($)

Richard J. Smith

60,000⁽¹⁾

91.82

1/25/2017

16,666

33,334⁽²⁾

68.89

1/26/2016

26,666

13,334⁽³⁾

69.47

1/27/2015

63,600

58.60

3/02/2014

7,640

51.50

1/25/2011

7,560

51.50

8/30/2009

7,577

51.50

1/27/2010

50,000

44.45

1/30/2013

8,013

45.45

8/30/2009

16,987

45.45

1/27/2010

70,000

41.69

2/11/2012

39,428

37.00

1/25/2011

11,250⁽⁴

⁾

1,344,600

15,000⁽⁵

⁾

1,792,800

John R. McGaha

16,500⁽¹⁾

91.82

1/25/2017

6,000

12,000⁽²⁾

68.89

1/25/2016

13,333

6,667⁽³⁾

69.47

1/27/2015

24,000

58.60

3/02/2014

20,430

70.71

2/11/2012

8,617

70.71

1/25/2011

1,575

67.27

1/25/2011

818

70.71

1/27/2010

5,250⁽⁴

⁾

$627,480

6,000⁽⁵

⁾

$717,120


(1)		Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/25/2008, 1/25/2009 and 1/25/2010.

(2)		Consists of options that vested or will vest as follows: 1/2 of the unexercisable options vest on each of 1/26/2008 and 1/26/2009.

(3)		The remaining unexercisable options vested on 1/27/2008.

(4)		Consists of performance units that will vest on December 31, 2009 only if, and to the extent that, there is satisfaction of the performance conditions described under “Long-Term Compensation—Performance Unit Program” in “Compensation Discussion and Analysis.” The performance conditions are subject to adjustment to reflect the circumstances of our separation from Entergy.

(5)		Consists of performance units that will vest on December 31, 2008 only if, and to the extent that, there is satisfaction of the performance conditions described under “Long-Term Compensation—Performance Unit Program” in “Compensation Discussion and Analysis.” The performance conditions are subject to adjustment to reflect the circumstances of our separation from Entergy.

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2007 Pension Benefits

The following table shows the present value as of December 31, 2007 of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, under the retirement plans sponsored by Entergy, determined using interest rate and mortality rate assumptions consistent with those used in Entergy’s financial statements. Additional information regarding these retirement plans is included in “Compensation Discussion and Analysis” and following this table.

Number

Present

of Years

Value of

Payments

Credited

Accumulated

During

Plan

Service

Benefit

2007

Name

(#)

($)

(a)

(b)

(c)

(d)

(e)

Richard J. Smith⁽¹⁾

Non-qualified Pension

31.25

Equalization Plan

$2,643,400

Qualified defined

8.33

benefit plan

$152,300

John R. McGaha

Non-qualified Pension

29.75

$1,540,200

Equalization Plan
Supplemental

29.75

$1,496,700

Retirement Plan

Qualified defined

29.75

benefit plan

$650,100

(1) Mr. Smith entered into an agreement granting 22.92 additional years of service under the non-qualified Pension Equalization Plan providing an additional $1,012,400 above the present value of accumulated benefit he would receive under the non-qualified System Executive Retirement Plan.

Qualified Retirement Benefits

The qualified retirement plan is a funded defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of the Entergy companies. All Named Executive Officers are participants in this plan. The pension plan provides a monthly benefit payable for the participant’s lifetime beginning at age 65 and equal to 1.5% of the participant’s five-year average monthly eligible earnings times such participant’s years of service. Participants are 100% vested in their benefit upon completing five years of vesting service.

Normal retirement under the plan is age 65. Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit payable as early as age 55 that is actuarially equivalent to the normal retirement benefit (i.e., reduced by 7% per year for the first five years preceding age 65, and reduced by 6% for each additional year thereafter). Employees who are at least age 55 with 10 years of vesting service upon termination from employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.

Nonqualified Retirement Benefits

The Named Executive Officers are eligible to participate in certain nonqualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan (PEP), the Supplemental Retirement Plan (SRP) and the System Executive Retirement Plan (SERP). Each of these plans is an unfunded nonqualified defined benefit pension plan that provides benefits to certain key management employees. In these plans, as described below and in “Compensation Discussion and Analysis,” an executive is typically enrolled in one or more plans but only paid the amount due under the plan (or combination of plans) that provides the highest benefit; in the case of Mr. McGaha (as explained below, the only Named Executive Officer who participates in the SRP), the combined benefits under the PEP and SRP will be paid unless the

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SERP benefit is greater (which is not presently the case), in which case the SERP benefit would be paid. In general, upon disability, participants in the PEP, Supplemental Retirement Plan and SERP remain eligible for continued service credits until recovery or retirement. Generally, spouses of participants who die before commencement of benefits are eligible for a portion of the participant’s accrued benefit.

The PEP

All of the Named Executive Officers are participants in the PEP. The benefit provisions are substantially the same as the qualified retirement plan but provide two additional benefits: (a) “restorative benefits” intended to offset limitations on certain earnings that may be considered in connection with the qualified retirement plan and (b) supplemental credited service (if granted to an individual participant). The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. Participants may elect to receive their PEP benefit in the form of a monthly annuity or an actuarially equivalent lump sum payment. The PEP benefit attributable to supplemental credited service is not vested until age 65. Subject to the approval of the Entergy employer (which approval is deemed given following a change in control of Entergy), an employee who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the benefit beginning as early as age 55. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.

The SRP

Mr. McGaha is the only Named Executive Officer who is currently in the SRP. The SRP provides that, under certain circumstances, a participant may receive a monthly retirement benefit payment for 120 months or elect a lump sum payment. The SRP benefit is not vested until age 65. Subject to the approval of the Entergy employer (which approval is deemed given following a change in control of Entergy), an employee who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the benefit beginning as early as age 55. Benefits payable prior to age 65 may be subject to certain reductions if the participant has less than 10 years of service. Mr. McGaha has attained age 55 and has more than 10 years of service under the SRP, and he is eligible for a lump-sum distribution under the SRP.

The SERP

All Named Executive Officers are participants in the SERP. The SERP provides a monthly benefit payable for the employees’ lifetime beginning at age 65, as further described in “Compensation Discussion and Analysis.” The SERP benefit is not vested until age 65. Subject to the approval of the Entergy employer, an employee who terminates his or her employment prior to age 65 may be vested in the SERP benefit, with payment of the benefit beginning as early as age 55. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits. Further, in the event of a change in control, participants in the SERP are also eligible for subsidized early retirement as early as age 55 even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment.

Additional Information

Please see “Compensation Discussion and Analysis” for additional description of the material terms and conditions of payments and benefits available under the Entergy retirement plans. For a discussion of the relevant assumptions used in valuing these liabilities, see Note 11 to the Financial Statements in Entergy’s Form 10-K for the year ended December 31, 2007.

2007 Nonqualified Deferred Compensation

The following table provides information regarding the Executive Deferred Compensation Plan (EDCP), the Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (EOP) and the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (2007 Equity Plan), which are plans of Entergy that allow for the deferral of compensation for

127

our Named Executive Officers. Please see “Compensation Discussion and Analysis” for additional information about the deferral opportunities under these plans.

All deferrals are credited to the applicable Entergy employer’s non-funded liability account. Depending on the payment deferred, the participating Named Executive Officers may elect investment in either phantom Entergy common stock or one or more of several investment options under the Savings Plan. Within limitations of the program, participating Named Executive Officers may move funds from one deemed investment option to another. The participating Named Executive Officers do not have the ability to withdraw funds from the deemed investment accounts except within the terms provided in their deferral elections. Within the limitations prescribed by law as well as the program, participating Named Executive Officers have the option to make a successive deferral of these funds. Assuming a Named Executive Officer does not elect a successive deferral, the Entergy employer of the participant is obligated to pay the amount credited to the participant’s account at the conclusion of his or her deferral. These payments are paid out of the general assets of the employer and are payable, in the case of the EOP and 2007 Equity Plan, in a lump sum, and in the case of the EDCP, in a lump sum or installments over not more than five years.

FICA and Medicare taxes are paid on all deferred amounts prior to their deferral. Applicable federal and state income taxes are paid at the conclusion of their deferral. Employees are not eligible for a “match” of amounts that are deferred by them pursuant to the deferred compensation programs. With the exception of allowing for the deferral of federal and state income taxes, Entergy provides no additional benefit to the Named Executive Officers in connection with amounts deferred under the deferred compensation plans. Deferred amounts are deemed credited with earnings or losses based on the rate of return of deemed investment options (under the EDCP) or Entergy common stock (under the EOP and 2007 Equity Plan).


	Executive	Registrant			Aggregate
	Contributions	Contributions	Aggregate	Aggregate	Balance at
	in	in	Earnings in	Withdrawals/	December 31,
	2007	2007	2007⁽²⁾	Distributions	2007
Name	($)	($)	($)	($)	($)
(a)	(b)	(c)	(d)	(e)	(f)

Richard J. Smith	$359,459⁽¹⁾	$	$1,735,408	$(579,053)	$8,768,192

John R. McGaha	$-	$-	$481,518	($1,098,250)	$3,014,343


(1)		Amounts in this column are included in column (g) for Mr. Smith in the 2007 Summary Compensation Table.

(2)		Amounts in this column are not included in the Summary Compensation Table.

Potential Payments upon Termination or Change in Control

Except as described below, there are no written agreements or plans applicable to any of our Named Executive Officers that would provide compensation in the event of a termination of employment or change in control. We have not yet determined what, if any, written agreements or plans will provide severance or change in control protections following the separation. However, we expect that any such agreements or plans that we adopt will be substantially similar to the agreements and plans of Entergy in effect prior to the distribution as described below.

Estimated Payments

The tables below reflect the amount of compensation each Named Executive Officer would have received upon the occurrence of the specified separation triggering events, under existing arrangements with Entergy, assuming that the separation was effective on December 31, 2007, the last business day of Entergy’s last fiscal year, and that the applicable Entergy stock price is $119.52, which was the closing market price on such date.

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Richard J. Smith — Chief Executive Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which Mr. Smith would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2007:


			Termination					Termination
Benefits and			for Good					Related to a
Payments Upon	Voluntary	For	Reason or				Change in	Change in
Termination⁽¹⁾	Resignation	Cause	Not for Cause	Retirement⁽⁶⁾	Disability	Death	Control⁽⁸⁾	Control


Severance Payment⁽²⁾	---	---	---	---	---	---	---	$3,163,659
Performance Units:⁽³⁾
2006-2008	---	---	---	---	$478,080	$478,080	---	$717,120
Performance Unit Program 2007-2009	---	---	---	---	$179,280	$179,280	$537,840	$537,840
Performance Unit Program
Unvested Stock	---	---	---	---	$4,017,067	$1,662,000⁽⁷⁾	$1,662,000	$4,017,067
Options⁽⁴⁾
Medical and Dental	---	---	---	---	---	---	---	$34,332
Benefits⁽⁵⁾
280G Tax Gross-up	---	---	---	---	---	---	---	$2,945,124

(1) In addition to the payments and benefits in the table, Mr. Smith also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see “2007 Pension Benefits.” In the event of a termination related to a change in control, pursuant to the terms of the Pension Equalization Plan, Mr. Smith would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. Smith’s employment were terminated for cause, he would not receive a benefit under the Pension Equalization Plan.

(2) In the event of a termination related to a change in control, Mr. Smith would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to 2.99 times the sum of his base salary plus annual incentive, calculated at target opportunity.

(3) In the event of a termination related to a change in control, Mr. Smith would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum payment relating to his performance units. The payment is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, the value of Mr. Smith’s awards were calculated as follows:

2006 - 2008 Plan – 6,000 performance units at target, assuming a stock price of $119.52; and

2007 - 2009 Plan – 4,500 performance units at target, assuming a stock price of $119.52.

With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.

(4) In the event of disability or a termination related to a change in control, all of Mr. Smith’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the 10-year term extending from the grant date of the options. For purposes of this table, we assumed that Mr. Smith exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2007, and the exercise price of each option share.

(5) Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Smith would be eligible to receive subsidized medical and dental benefits for a period of 36 months.

(6) As of December 31, 2007, compensation and benefits available to Mr. Smith under this scenario are substantially the same as available with a voluntary resignation.

(7) Under the 2007 Equity Ownership Plan (applicable to grants of equity awards made after January 1, 2007), in the event of a plan participant’s death, all unvested stock options would become immediately exercisable.

(8) Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:


	•	All unvested stock options would become immediately exercisable; and

	•	All performance units become vested (based on the assumption that all performance goals were achieved at target).

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John McGaha — Chief Operating Officer

The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which Mr. McGaha would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2007:


			Termination					Termination
Benefits and			for Good					Related to a
Payments Upon	Voluntary	For	Reason or				Change in	Change in
Termination⁽¹⁾	Resignation	Cause	Not for Cause	Retirement⁽⁶⁾	Disability	Death	Control⁽⁸⁾	Control


Severance Payment⁽²⁾	---	---	---	---	---	---	---	$1,280,000
Performance Units:⁽³⁾
2006-2008	---	---	---	---	$191,232	$191,232	---	$286,848
Performance Unit Program
2007-2009	---	---	---	---	$83,664	$83,664	$250,992	$250,992
Performance Unit Program
Unvested Stock Options⁽⁴⁾	---	---	---	---	$1,398,293	$457,050⁽⁷⁾	$457,050	$1,398,293
Medical and Dental Benefits⁽⁵⁾	---	---	---	---	---	---	---	$23,028
280G Tax Gross-up	---	---	---	---	---	---	---	---

(1) In addition to the payments and benefits in the table, Mr. McGaha also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see “2007 Pension Benefits.” If Mr. McGaha’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits, which are described in “2007 Pension Benefits.” If Mr. McGaha’s employment were terminated for cause, he would forfeit his System Executive Retirement Plan and other supplemental benefits.

(2) In the event of a termination related to a change in control, Mr. McGaha would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to two times his base salary plus annual incentive, calculated at target opportunity.

(3) In the event of a termination related to a change in control, Mr. McGaha would have been entitled to receive pursuant to the System Executive Continuity Plan a lump sum payment relating to his performance units. The payment is calculated as if all performance goals relating to the performance unit were achieved at target level. For purposes of the table, the value of Mr. McGaha’s awards have been calculated as follows:

2006 - 2008 Plan – 2,400 performance units at target, assuming a stock price of $119.52; and

2007 - 2009 Plan – 2,100 performance units at target, assuming a stock price of $119.52.

For scenarios other than a termination related to a change in control, the award is not enhanced or accelerated by the termination event. With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.

(4) In the event of disability or a termination related to a change in control, all of Mr. McGaha’s unvested stock options would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. McGaha exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2007, and the applicable exercise price of each option share.

(5) Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. McGaha would be eligible to receive subsidized medical and dental benefits for a period of 24 months.

(6) As of December 31, 2007, compensation and benefits available to Mr. McGaha under this scenario are substantially the same as available with a voluntary resignation.

(8) Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change of control without regard to whether their employment is terminated as a result of a change of control. The accelerated benefits in the event of a change in control are as follows:


	•	All unvested stock options would become immediately exercisable; and

	•	All performance units become vested (based on the assumption that all performance goals were achieved at target).

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In the following sections, additional information is provided regarding certain of the scenarios described in the tables above:

Termination Related to a Change in Control

Under the System Executive Continuity Plan, the Named Executive Officers will be entitled to the benefits described in the tables above in the event of a termination related to a change in control if their employment is terminated other than for cause or if they terminate their employment for good reason, in each case within a period commencing 90 days prior to and ending 24 months following a change in control.

A change in control includes the following events:


	•	The purchase of 25% or more of either the common stock or the combined voting power of the voting securities of Entergy;

	•	the merger or consolidation of Entergy (unless Entergy’s board members constitute at least a majority of the board members of the surviving entity);

	•	the liquidation, dissolution or sale of all or substantially all of Entergy’s assets; or

	•	a change in the composition of Entergy’s board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy’s board at the end of the period.

The proposed separation does not constitute a “Change in Control” for purposes of the System Executive Continuity Plan.

Entergy may terminate a Named Executive Officer’s employment for cause under the System Executive Continuity Plan if he:


	•	fails to substantially perform his duties for a period of 30 days after receiving notice from the Entergy board;

	•	engages in conduct that is injurious to Entergy or any of its subsidiaries;

	•	is convicted of or pleads guilty to a felony or other crime that materially and adversely affects his ability to perform his or her duties or Entergy’s reputation;

	•	violates any agreement with Entergy or any of its subsidiaries; or

	•	discloses any of Entergy’s confidential information without authorization.

A Named Executive Officer may terminate employment with Entergy for good reason under the System Executive Continuity Plan if, without the Named Executive Officer’s consent:


	•	the nature or status of his duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;

	•	his salary is reduced by 5% or more;

	•	he is required to be based outside of the continental United States at somewhere other than the primary work location prior to the change in control;

	•	any of his compensation plans are discontinued without an equitable replacement;

	•	his benefits or number of vacation days are substantially reduced; or

	•	his employment is purported to be terminated other than in accordance with the System Executive Continuity Plan.

In addition to participation in the System Executive Continuity Plan, upon the completion of a transaction resulting in a change in control of Entergy, benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan and Supplemental Retirement Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason.

131

Any awards granted under the 2007 Equity Ownership Plan will become fully vested upon a change in control without regard to whether the executive is involuntarily terminated without cause or terminates employment for good reason.

Under certain circumstances, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:


	•	accepts employment with Entergy or any of its subsidiaries;

	•	elects to receive the benefits of another severance or separation program;

	•	removes, copies or fails to return any property belonging to Entergy or any of its subsidiaries;

	•	discloses non-public data or information concerning Entergy or any of its subsidiaries; or

	•	violates his non-competition provision, which generally runs for two years but extends to three years if permissible under applicable law.

Furthermore, if the executive discloses non-public data or information concerning Entergy or any of its subsidiaries or violates their non-competition provision, he will be required to repay any benefits previously received under the System Executive Continuity Plan.

Termination for Cause

If a Named Executive Officer’s employment is terminated for “cause” (as defined in the System Executive Continuity Plans and described above under “Termination Related to a Change in Control”), he is generally entitled to the same compensation and separation benefits described below under “Voluntary Resignation.”

Voluntary Resignation

If a Named Executive Officer voluntarily resigns, he is entitled to all accrued benefits and compensation as of the resignation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees. In the case of voluntary resignation, the officer would forfeit all unvested stock options and restricted units as well as any perquisites to which he is entitled as an officer. In addition, the officer would forfeit, except as described below, his right to receive incentive payments under the Performance Unit Program or the Annual Incentive Plan. If the officer resigns after the completion of an Annual Incentive Plan or Performance Unit Program performance period, he could receive a payout under the Performance Unit Program based on the outcome of the performance cycle and could, at Entergy’s discretion, receive an annual incentive payment under the Annual Incentive Plan. Any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment.

Retirement

Under Entergy’s retirement plans, a Named Executive Officer’s eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the qualified retirement plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan, Supplemental Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of the employer.

Upon a Named Executive Officer’s retirement, he is generally entitled to all accrued benefits and compensation as of the retirement date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees. The annual incentive payment under the Annual Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Performance Unit Program are pro-

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rated based on the actual number of days employed, in each outstanding performance cycle, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle, consistent with the timing of payments to active participants in the Annual Incentive Plan and the Performance Unit Program, respectively.

Unvested stock options issued under the 2007 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options. Any restricted units held (other than those issued under the Performance Unit Program) by the executive upon his retirement are forfeited, and perquisites (other than short-term financial counseling services) are not available following the retirement date.

Disability

If a Named Executive Officer’s employment is terminated due to disability, he generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that restricted units may be subject to specific disability benefits (as noted, where applicable, in the tables above).

Death

If a Named Executive Officer dies while actively employed, he generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that:


	•	all unvested stock options granted prior to January 1, 2007 are forfeited;

	•	vested stock options will expire the earlier of ten years from the grant date or three years following the executive’s death; and

	•	restricted units may be subject to specific death benefits (as noted, where applicable, in the tables above).

Non-Employee Director Compensation

Our Director Compensation Following the Distribution

We have not yet established arrangements to compensate our directors for their services to us following the distribution. However, we expect initially to establish arrangements that are similar to those in place for directors serving on the Entergy board. Set out below is a discussion of the compensation arrangements that were in place for non-employee Entergy directors for 2007.

Entergy Director Compensation for 2007

Entergy uses a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on the board of Entergy. In setting director compensation, Entergy considers the significant amount of time that directors expend in fulfilling their duties to Entergy as well as the skill-level required by Entergy of members of the Entergy board.

Cash Compensation

Each non-employee director receives a quarterly cash retainer equal to the value of 75 shares of Entergy common stock. In addition to receiving a quarterly cash retainer, each non-employee director receives a cash fee for attending Board and committee meetings as follows:


Meeting		Fee

Board Meetings		$1,500
Committee Meetings ⁽¹⁾(in conjunction with Board meetings)		$1,000
Committee Meetings ⁽¹⁾(different location from Board and other committee meetings)		$2,000
Telephone Meetings		One-half of applicable fees

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(1) If a director attends a meeting of a committee on which that director does not serve as a member, he or she receives one-half of the applicable fees of an attending member.

Finally, the presiding director receives an annual cash retainer of $15,000, and each of the chairs of the Audit Committee and Nuclear Committee receives an annual cash retainer fee of $10,000. Each of the chairs of the Personnel Committee, Corporate Governance Committee and Finance Committee receives an annual cash retainer of $5,000.

Equity-Based Compensation

All non-employee directors receive two types of equity-based compensation grants: common stock and phantom units (which are the economic equivalent of one share of Entergy common stock).

Common Stock. Each non-employee director receives a quarterly grant of 150 shares of Entergy common stock. Directors may defer receipt of these shares subject to certain conditions. Deferred shares accrue dividend equivalents until the shares are received.

Phantom Units. Under the Service Recognition Program for Outside Directors, non-employee directors are credited with 800 phantom units representing shares of Entergy common stock for each year of service on the board. After five years, the director’s rights in the phantom units vest and he or she becomes entitled to receive, upon the conclusion of his or her service on the board, the cash equivalent for each vested unit of one share of Entergy common stock on the date of the director’s retirement or separation from the board. Phantom units accumulate dividend equivalents. In the event of a change in control (as defined in the plan, which definition excludes the separation) and the termination of the director’s service, the phantom units vest and become immediately payable.

Other Benefits

Non-employee directors receive $1,500 for participation in director education programs, director orientation or business sessions, inspection trips or conferences not held on the same day as a board meeting. Entergy reimburses non-employee directors for their expenses in attending board and committee meetings, director education programs and other board-related activities. Entergy also purchases director and officer liability insurance, life insurance, accidental death and disability insurance and aircraft accident insurance for its non-employee directors. In addition, each non-employee director may receive at Entergy’s expense an annual physical.

Director Compensation for 2007

The following table sets forth information concerning the compensation for 2007 awarded by Entergy to individuals who were non-employee directors of Entergy during 2007 and who will be our directors at the time of the separation.

Fees

Earned

or Paid

Option

All Other

in Cash

Stock Awards

Awards

Compensation

Total

Name

($)

(a)

(b)

(c)

(d)

(g)

(h)

Excluding

With

Stock

Retirement

Grants

Accruals

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table provides information with respect to the expected beneficial ownership of our common stock by (i) each of our shareholders who we believe will be a beneficial owner of more than 5% of our outstanding common stock, (ii) each of the persons nominated to serve as our directors, (iii) each officer named in the Summary Compensation Table, and (iv) all of our executive officers and director nominees as a group. We based the share amounts on each person’s beneficial ownership of Entergy common stock as of May 8, 2008, unless we indicate some other basis for the share amounts and assuming a distribution ratio of one share of our common stock for each share of Entergy common stock.

Except as otherwise noted in the footnotes below, each person or entity identified below has sole voting and investment power with respect to such securities. Following the distribution, we will have outstanding an aggregate of approximately million shares of common stock, based upon approximately shares of Entergy common stock outstanding on , excluding treasury shares and assuming no exercise of Entergy options, and applying the distribution ratio of shares of our common stock for each share of Entergy common stock held as of the record date.

To the extent our directors and officers own Entergy common stock at the time of the separation, they will participate in the distribution on the same terms as other holders of Entergy common stock.


	# of Shares
Name of Beneficial Owner	to be Owned	% of Class


5% Shareholders:
Barrow, Hanley, Mewhinney & Strauss, Inc.⁽¹⁾	10,723,669	5.5
Capital World Investors⁽²⁾	10,922,600	5.6
FMR LLC⁽³⁾	12,026,829	6.2

Directors and Executive Officers:
Richard Smith⁽⁴⁾	427,070	*
John R. McGaha⁽⁴⁾	114,383	*

All directors and executive officers as a group ( persons)

* The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed 1% of the outstanding Entergy Corporation common stock.

(1) Based on a Schedule 13G filed with the SEC on February 13, 2008, Barrow, Hanley, Mewhinney & Strauss, Inc. has indicated that it has sole voting power over 3,577,984 shares, shared voting power with respect to 7,145,685 shares and sole power to dispose or direct the disposition over 10,723,669 shares. The address for Barrow, Hanley, Mewhinney & Strauss, Inc. is One McKinney Plaza, 3232 McKinney Avenue, 15th Floor, Dallas, Texas 75204-2429.

(2) Based on a Schedule 13G filed with the SEC on February 11, 2008, Capital World Investors, a division of Capital Research and Management Company, has indicated that it has sole power to dispose or direct the disposition over 10,922,600 shares. The address for Capital World Investors is 333 South Hope Street, Los Angeles, California 90071.

(3) Based on a Schedule 13G/A filed with the SEC on February 14, 2008, FMR LLC has indicated that it has sole voting power over 481,790 shares and sole power to dispose or direct the disposition over 12,026,829 shares. The address for FMR LLC is 82 Devonshire Street, Boston, Massachusetts 02109.

(4) Includes the following: Mr. McGaha, 7,006 shares, 92,940 shares underlying options exercisable within 60 days, and 14,337 shares underlying phantom units; Mr. Smith, 7,620 shares, 364,137 shares underlying options exercisable within 60 days, and 55,313 shares underlying phantom units. Each executive holds the phantom units under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan. These units will be paid out in either Entergy Corporation common stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation, the phantom units are issued under the Service Recognition Program for Outside Directors. All non-employee directors are credited with units for each year of service on the board.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Distribution from Entergy

The distribution will be accomplished by Entergy distributing all of its shares of our common stock to holders of Entergy common stock entitled to such distribution, as described in the section entitled “The Separation.” Completion of the distribution will be subject to satisfaction or waiver by Entergy of the conditions to the separation and distribution described below.

Agreements with Entergy

We will enter into the Separation and Distribution Agreement and several other agreements with Entergy or EquaGen to effect the separation and provide a framework for our relationships with Entergy, Entergy’s other businesses and EquaGen after the separation. These agreements will govern the relationship among us, EquaGen, Entergy and Entergy’s other businesses subsequent to the completion of the separation, and provide for the allocation among us, EquaGen, Entergy and Entergy’s other businesses of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) relating to the non-utility nuclear business attributable to periods prior to, at and after our separation from Entergy. In addition to the Separation and Distribution Agreement (which contains many of the key provisions related to our separation from Entergy and the distribution of our shares of common stock to Entergy shareholders), these agreements include:


	•	Joint Venture Agreements;

	•	Operating Agreements with Entergy Nuclear Operations;

	•	Shared Services Agreements between EquaGen and each of Entergy Services, Inc. and Entergy Operations, Inc.;

	•	Corporate Services Agreement between Entergy Services, Inc. and EquaGen;

	•	Transition Services Agreement;

	•	Tax Sharing Agreement; and

	•	Employee Matters Agreement.

The agreements described below and the summaries of each of these agreements set forth the terms of the agreements that we believe are material. These summaries are qualified by the full text of the applicable agreements. The terms of the agreements described below that will be in effect following our separation have not yet been finalized; changes, some of which may be material, may be made prior to our separation from Entergy.

Separation Costs

Entergy expects to incur pre-tax separation costs of approximately $ million of which approximately $ million will be allocated to us in the separation or incurred by us after the separation. Over the 12 months following the separation, the portion of these pre-tax costs incurred by us is expected to be approximately $ to $ million. Certain of the separation costs, primarily costs for the development of new information systems, are expected to be capitalized.

The expected costs include:


	•	fees for professional services, including financial advisors, legal, accounting and other business consultants;

	•	costs for branding the new company, replacing signage and investor and other stakeholder communications; and

	•	costs related to the incurrence of debt to be paid to or exchanged by Entergy.

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Separation and Distribution Agreement

The following discussion summarizes the material provisions of the Separation and Distribution Agreement. The Separation and Distribution Agreement will set forth our agreements with Entergy regarding the principal transactions necessary to separate us from Entergy. It will also set forth other agreements that govern certain aspects of our relationships with Entergy after the completion of the separation. We intend to enter into the Separation and Distribution Agreement immediately before the record date for the distribution of our shares of common stock to Entergy shareholders, and the Separation and Distribution Agreement will become effective upon such distribution.

Transfer of Assets and Assumption of Liabilities

The Separation and Distribution Agreement will identify assets to be transferred, liabilities to be assumed and contracts to be assigned to each of us and Entergy as part of the separation of Entergy into two companies, and it will describe when and how these transfers, assumptions and assignments will occur. In particular, the Separation and Distribution Agreement will provide that, subject to the terms and conditions contained in the Separation and Distribution Agreement:


	•	all of the assets and liabilities (including whether accrued, contingent or otherwise) primarily related to our business (the business and operations of Entergy’s non-utility nuclear business) will be retained by or transferred to us or one of our subsidiaries;

	•	all of the assets and liabilities (including whether accrued, contingent or otherwise) primarily related to the business and operations of Entergy’s regulated utility business will be retained by Entergy;

	•	liabilities (including whether accrued, contingent or otherwise) related to, arising out of or resulting from businesses of Entergy that were previously terminated or divested will be allocated among the parties to the extent formerly owned or managed by or associated with such parties or their respective businesses;

	•	each party or one of its subsidiaries will assume or retain any liabilities (including under applicable federal and state securities laws) relating to, arising out of or resulting from any registration statement or similar disclosure document which offers for sale any security after the separation;

	•	each party or one of its subsidiaries will assume or retain any liabilities (including under applicable federal and state securities laws) relating to, arising out of or resulting from any registration statement or similar disclosure document which offers for sale any security prior to the separation to the extent such liabilities arise out of, or result from, matters related to businesses, operations, assets or liabilities allocated to the party in the separation;

	•	Entergy will assume or retain any liability relating to, arising out of or resulting from any registration statement or similar disclosure document related to the separation (including the Form 10 and this information statement), but only to the extent such liability derives from a material misstatement or omission contained in the sections entitled “The Separation” and “Certain Relationships and Related Party Transactions — Agreements with Entergy” and the section entitled “Summary” only to the extent it is summarizing the preceding sections; we will assume or retain any other liability relating to, arising out of or resulting from any registration statement or similar disclosure document related to the separation;

	•	each party or one of its subsidiaries will assume or retain any liabilities relating to, arising out of or resulting from any of its or its subsidiaries’ or controlled affiliates’ indebtedness (including debt securities and asset-backed debt), regardless of the issuer of such indebtedness, exclusively relating to its business or secured exclusively by its assets;

	•	each party or one of its subsidiaries will assume or retain any liabilities relating to, arising out of or resulting from any guarantees exclusively relating to its business or secured exclusively by its assets;

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	•	except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, other than the costs and expenses relating to legal counsel, financial advisors and accounting advisory work incurred prior to the separation, we will be responsible for any costs or expenses we incur in connection with the separation;

	•	except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, Entergy will be responsible for any costs or expenses it incurs in connection with the separation and the costs and expenses relating to legal counsel, financial advisors and accounting advisory work related to the separation.

Except as may expressly be set forth in the Separation and Distribution Agreement or any ancillary agreement, all assets will be transferred on an “as is,” “where is” basis and the respective transferees will bear the economic and legal risks that (i) any conveyance will prove to be insufficient to vest in the transferee good title, free and clear of any security interest, and (ii) any necessary consents or governmental approvals are not obtained or that any requirements of laws or judgments are not complied with.

Information in this information statement with respect to the assets and liabilities of the parties following the separation is presented based on the allocation of such assets and liabilities pursuant to the Separation and Distribution Agreement, unless the context otherwise requires. Certain of the liabilities and obligations to be assumed by one party or for which one party will have an indemnification obligation under the Separation and Distribution Agreement and the other agreements relating to the separation are, and following the separation may continue to be, the legal or contractual liabilities or obligations of another party. Each such party that continues to be subject to such legal or contractual liability or obligation will rely on the applicable party that assumed the liability or obligation or the applicable party that undertook an indemnification obligation with respect to the liability or obligation, as applicable, under the Separation and Distribution Agreement to satisfy the performance and payment obligations or indemnification obligations with respect to such legal or contractual liability or obligation.

Future Claims

The Separation and Distribution Agreement will provide for the formation of a contingent claim committee, which will have the responsibility for determining whether any newly discovered asset or liability is an asset or liability of Entergy or us, or is an unallocated asset or unallocated liability. The contingent claim committee will be comprised of one representative each from Entergy and Enexus Energy. Resolution of a matter submitted to the contingent claim committee will require the unanimous approval of the representatives.

Intercompany Accounts

The Separation and Distribution Agreement will provide that, subject to any provisions in the Separation and Distribution Agreement or any ancillary agreement to the contrary and except for specified intercompany accounts, prior to the separation from Entergy, intercompany accounts will be scheduled and either (i) repaid at closing, (ii) continue in effect post closing, or (iii) deemed satisfied prior to the effective time of the separation, with such satisfaction being treated as a distribution and a contribution to capital for United States federal income tax purposes, as appropriate.

Trademarks

Except as otherwise specifically provided in any ancillary agreement and subject to certain limitations, the Separation and Distribution Agreement will provide that the “Entergy” name will be retained by Entergy. From and after the separation, each of Enexus Energy and Entergy will promptly (and in any event no later than three months following the separation) cease using the trademarks and other intellectual property allocated to the other party.

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Releases

Except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, each party will release and forever discharge the other party and its respective subsidiaries and affiliates from all liabilities existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the separation from Entergy. The releases will not extend to obligations or liabilities under any agreements between the parties that remain in effect following the separation pursuant to the Separation and Distribution Agreement, the Joint Venture Agreement, the Operating Agreement or any other ancillary agreement.

Indemnification

In addition, the Separation and Distribution Agreement will provide for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of Entergy’s business with Entergy. Specifically, each party will indemnify, defend and hold harmless the other party, its affiliates and subsidiaries and its officers, directors, employees and agents for any losses arising out of or otherwise in connection with:


	•	the liabilities each such party assumed or retained pursuant to the Separation and Distribution Agreement;

	•	such party’s specified percentage of unallocated liabilities; and

	•	any breach by such party of the Separation and Distribution Agreement.

Legal Matters

Each party to the Separation and Distribution Agreement will assume the liability for, and control of, all pending and threatened legal matters related to its own business or assumed or retained liabilities and will indemnify the other parties for any liability arising out of or resulting from such assumed legal matters.

Each party to a claim will agree to cooperate in defending any claims against both parties for events that took place prior to, on or after the date of the separation of such party from Entergy.

Unless otherwise specified in the Separation and Distribution Agreement or agreed to by the parties, Entergy will act as managing party and manage and assume control of all legal matters related to any unallocated asset or unallocated liability. The parties shall each be responsible for their respective share of all out-of-pocket costs and expenses related thereto.

Insurance

The Separation and Distribution Agreement will provide for the allocation among the parties of rights and obligations under existing insurance policies with respect to occurrences prior to the separation and will set forth procedures for the administration of insured claims. In addition, the Separation and Distribution Agreement will provide that as of the separation Entergy and we shall be solely responsible for our respective programs of insurance, which shall be separate and apart from one another.

Further Assurances

To the extent that any transfers contemplated by the Separation and Distribution Agreement have not been consummated on or prior to the date of the separation, the parties will agree to cooperate to effect such transfers as promptly as practicable following the date of the separation. In addition, each of the parties will agree to cooperate with each other and use commercially reasonable efforts to take or to cause to be taken all actions, and to do, or to cause to be done, all things reasonably necessary under applicable law or contractual obligations to consummate and make effective the transactions contemplated by the Separation and Distribution Agreement and the ancillary agreements.

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Dispute Resolution

In the event of any dispute arising out of the Separation and Distribution Agreement, the general counsels of the parties will negotiate for a reasonable period of time to resolve any disputes among the parties. If the parties are unable to resolve disputes in this manner, the disputes will be resolved through binding arbitration.

The Distribution

The Separation and Distribution Agreement will also govern the rights and obligations of the parties regarding the proposed distribution. Prior to the distribution, we will distribute to Entergy as a stock dividend the number of shares of our common stock distributable in the distribution. Entergy will cause its agent to distribute to Entergy shareholders that hold shares of Entergy common stock as of the applicable record date all the issued and outstanding shares of our common stock.

Additionally, the Separation and Distribution Agreement will provide that the distribution is subject to several conditions that must be satisfied or waived by Entergy in its sole discretion. For further information regarding our separation from Entergy, see “The Separation — Conditions to the Distribution.”

Other Matters Governed by the Separation and Distribution Agreement

Other matters governed by the Separation and Distribution Agreement include access to financial and other information, confidentiality, access to and provision of records and treatment of outstanding guarantees and similar credit support.

Joint Venture Agreements

The Joint Venture

In connection with the separation, Entergy Nuclear, Inc., currently a wholly-owned subsidiary of Entergy, will become a limited liability company and change its name to EquaGen LLC. We and Entergy will each own a 50% interest in EquaGen prior to completion of the distribution of our common stock. EquaGen is expected to operate the nuclear assets owned by us, and to provide certain services to the regulated nuclear utility operations of Entergy and to third parties. EquaGen will allow certain nuclear operations expertise currently in place at each of Entergy’s nuclear power plant to be accessible by both us and Entergy after the separation.

Joint Venture Structure

Upon completion of the transactions contemplated by the Joint Venture Agreements, EquaGen will own Entergy Nuclear Operations and TLG Services, Inc.

Joint Venture Formation

The Joint Venture Formation Agreement identifies the assets and liabilities to be assumed and contracts to be assigned to EquaGen. In particular, the Joint Venture Formation Agreement will provide that, subject to the terms and conditions contained in the Joint Venture Formation Agreement:


	•	all of the assets and liabilities (including whether accrued, contingent or otherwise) primarily related to the non-utility nuclear services business will be retained by or transferred to EquaGen;

	•	EquaGen will be responsible for guarantees associated with the businesses of EquaGen. Where feasible, guarantees will be novated to reflect any assignment and assumption; however, if not feasible, the legally responsible party will be indemnified for such guarantee by EquaGen;

	•	except as may expressly be set forth in the Joint Venture Formation Agreement, all assets will be transferred on an “as is,” “where is” basis and EquaGen will bear the economic and legal risks that (i) any conveyance will prove to be insufficient to vest in EquaGen good title, free and clear of any

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		security interest, and (ii) any necessary consents or governmental approvals are not obtained or that any requirements of laws or judgments are not complied with; and


	•	except as otherwise provided in the Joint Venture Formation Agreement, EquaGen will release and forever discharge Entergy and Enexus Energy and their respective subsidiaries and affiliates from all liabilities existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the separation from Entergy. The releases will not extend to obligations or liabilities under any agreements between the parties that remain in effect following the separation pursuant to the Separation and Distribution Agreement, the Joint Venture Agreements, the Shared Services Agreements, the Operating Agreements or any other ancillary agreement.

In addition, the Joint Venture Formation Agreement will provide for indemnification by EquaGen in favor of Entergy and Enexus Energy and each of its respective members, directly arising in connection with liabilities retained or assumed by EquaGen.

Composition of Board of Managers

The business and affairs of EquaGen will be managed exclusively by a Board of Managers, initially consisting of six persons. Except as otherwise provided in the EquaGen LLC Limited Liability Company Agreement, each member of EquaGen possesses the right to appoint three persons to the Board of Managers, as well as the right to appoint the Chairman of the Board for alternating two year periods.

Significant Matters

Certain actions, defined as “Significant Matters”, cannot be taken without the approval of two-thirds of the votes cast by all of the managers at a meeting where a quorum is present. Examples of Significant Matters include:


	•	approval of the business plan or annual budget of EquaGen and any material amendment to the business plan or budget;

	•	single expenditures above $15 million, as well as incurring indebtedness in excess of $1 million;

	•	making any distributions to members;

	•	placing or permitting any liens to exist on the assets of EquaGen;

	•	approval of any contract between EquaGen (or its subsidiaries) and a member or any affiliate of any member; and

	•	policies regarding financial securities such as swaps, options or derivatives.

If the Board of Managers fails to approve a Significant Matter at two consecutive meetings, the matter is to be referred, initially, to the Chief Executive Officer of each member for resolution. If agreement is not reached by the Chief Executive Officers within the time limit specified in the EquaGen LLC Limited Liability Company Agreement, the matter is to be resolved by mediation or, in the event that mediation is unsuccessful, by binding arbitration.

Member Matters

Other matters, defined as “Member Matters”, cannot be taken without the unanimous approval of the members. Examples of Member Matters include:


	•	the issuance of any securities of EquaGen;

	•	mergers, acquisitions, joint ventures and partnerships;

	•	a sale or other disposition of all or substantially all of the assets of EquaGen;

	•	making or permitting capital contributions to EquaGen;

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	•	the variation of any rights attached to any securities of EquaGen, or any redemption, buy-back or cancellation of any issued securities; and

	•	any amendment to the EquaGen LLC Limited Liability Company Agreement.

Transfer of Membership Interests

A member may not transfer its membership interest in EquaGen to a third party unless all members agree. A member may transfer its membership interest to a wholly-owned subsidiary within its group or to its parent without the consent of other members. However, if the wholly-owned subsidiary purports to leave the member’s group, the membership interest transferred to it must be transferred “back” to the parent, or to another wholly-owned subsidiary of the member’s group.

Exercise Event

An “Exercise Event” occurs if EquaGen is operating four or fewer of our nuclear power plants and the unanimous Board of EquaGen fails to exercise its right to override the automatic termination of all remaining Operating Agreements. If all Operating Agreements are thus terminated (or if EquaGen is operating none of our nuclear power plants), Entergy has the right (within the time limits specified in the EquaGen LLC Limited Liability Company Agreement) to:


	•	direct EquaGen to sell all of its subsidiaries carrying on the third-party business of EquaGen to us; or

	•	sell all (but not part) of its membership interest in EquaGen to us.

The price at which we would be required to buy such assets would be determined initially by Entergy and us. If we are unable to agree on a price within the time limit specified in the EquaGen LLC Limited Liability Company Agreement, then the price will be determined by an independent third-party financial advisor according to the procedures specified in the EquaGen LLC Limited Liability Company Agreement.

Prohibition Against Solicitation of Key Employees

For two years after EquaGen is established, each member and its affiliates is prevented from soliciting, or attempting to solicit, a senior employee of EquaGen to terminate his or her employment with EquaGen. This restriction, however, is subject to exceptions set forth in the EquaGen LLC Limited Liability Company Agreement and also does not apply to the Entergy group in a sale of all of its membership interest in EquaGen. In that case, Entergy has the right to solicit and make offers to those officers and employees of EquaGen, in accordance with the provisions set forth in the EquaGen LLC Limited Liability Company Agreement.

Similarly, for two years after EquaGen is established, and except as otherwise provided in the EquaGen LLC Limited Liability Company Agreement, EquaGen is prohibited from soliciting, or attempting to solicit, any senior employee of a member (or a member of its group) from terminating his or her employment with the member (or the member of that member’s group).

Covenants

We agree, in the Joint Venture Formation Agreement, that:


	•	any nuclear power plants we acquire after the separation shall be operated by EquaGen; and

	•	we shall not sell a nuclear power plant to a third party unless (i) the third party accepts a transfer of the underlying Operating Agreement with EquaGen, (ii) the sale is the result of a change in ownership of a subsidiary that directly owns one of our nuclear power plants, or (iii) EquaGen consents to the sale.

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Operating Agreements

Following the separation, Entergy Nuclear Operations will continue as the NRC-licensed operator of the six operating nuclear power plants currently constituting Entergy’s non-utility nuclear business and which will be owned by us following the separation. Each of our non-utility nuclear power plants is owned by a separate, existing limited liability company. Following the separation, each owner will become a wholly-owned subsidiary of ours. As a result, in connection with the consummation of the separation, Entergy Nuclear Operations and each owner will enter into an Operating Agreement for each plant. The Operating Agreements will be based on a common form derived from the existing operating agreements, but will be amended primarily to insert commercial terms (e.g., fees, indemnities and termination provisions) to reflect the fact that, following the separation, the parties are no longer wholly-owned affiliates of Entergy.

Scope of Agreement and Services

Entergy Nuclear Operations will operate and make capital improvements to each nuclear power plant and maintain permits and approvals in accordance with good utility practice, applicable laws and regulations, the applicable NRC Operating License and the owner-approved budgets for each of the six operating nuclear power plants.

Fees

Each operating agreement will be based on a shared-risk budgetary process and a cost-plus-fees payment structure. Entergy Nuclear Operations will prepare, and the owner will approve, detailed, line-item annual budgets for operation and maintenance costs and capital expenditures.

Indemnities

Entergy Nuclear Operations and each owner will mutually indemnify each other for injuries to their own employees. Entergy Nuclear Operations will further indemnify each owner for claims arising from Entergy Nuclear Operations’ wrongful termination of the Operating Agreements, willful misconduct or gross negligence (capped at all fees paid by the owner to Entergy Nuclear Operations over the three-year period prior to such wrongful termination, willful misconduct, or gross negligence), but not for such claims arising out of nuclear incidents or nuclear hazards. Each owner will further indemnify Entergy Nuclear Operations for any claims by the owner’s employees or third parties arising out of Entergy Nuclear Operations’ performance under the Operating Agreement, except as contemplated above.

Limitations on Liabilities

No party will be liable for indirect, special, punitive, incidental or consequential damages except to the extent that such claims fall under either party’s indemnities, are related to the owners’ obligation to make termination payments, or are related to Entergy Nuclear Operations’ obligation to cover budgetary cost overruns. The owner will be obligated to pay costs associated with the occurrence of a nuclear incident, including the payment of primary and retroactive insurance premiums pursuant to the Price-Anderson Act.

Term

Each Operating Agreement will become effective on and from the separation and will expire on the date that the NRC operating license term for each nuclear power plant expires, unless earlier terminated (i) for cause, (ii) due to the acts of a court or governmental agency, declaring all or part of the Operating Agreement invalid or unenforceable or substantially impairing a party’s ability to perform, or (iii) by the owner without cause.

Termination

In the event of any termination, the owner is required to pay Entergy Nuclear Operations for all services provided through the date of termination and reimburse Entergy Nuclear Operations for operations and management and capital expenditure costs incurred. If an owner terminates without cause, or Entergy

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Nuclear Operations terminates for cause, the owner shall pay Entergy Nuclear Operations demobilization costs, including costs to transfer licenses and employees to a new operator. In addition, if an owner terminates without cause, the owner shall pay Entergy Nuclear Operations a termination fee based on the amount of fixed and variable fees forgone by Entergy Nuclear Operations. In the event of any termination, Entergy Nuclear Operations will continue to operate under the Operating Agreement until the termination has been approved by the NRC and the operating responsibilities have been transferred to a qualified NRC-approved operator.

EquaGen Shared Services Agreement

Under the EquaGen Shared Services Agreement, (i) EquaGen will provide support services to Entergy Operations, Inc., the NRC-licensed operator of Entergy’s fleet of regulated utility nuclear power plants; and (ii) the parties will provide field and maintenance services to each other.

Provision of Support Services

The support services will be provided in the areas of business development, licensing, emergency planning, operations support, oversight, planning and innovation and senior management.

Chief Nuclear Officer

As part of the support services, EquaGen will provide Entergy Operations, Inc. with a contract nuclear officer who shall serve as Entergy Operations, Inc.’s Chief Nuclear Officer.

Delegations of Authority

In view of Entergy Operations, Inc.’s role as the operating licensee for Entergy’s regulated utility nuclear power plants, the duties delegated to EquaGen’s personnel providing support services to Entergy Operations, Inc. (including the contracted Chief Nuclear Officer) exclude decisions regarding matters unrelated to the activities of Entergy’s regulated utility nuclear power plants. The specific delegations of power set forth in the agreement include matters that allow urgent decisions to be made on a timely basis and without invoking the NRC’s license transfer provisions.

Provision of Field and Maintenance Services

Subject to certain conditions and to the terms of any applicable collective bargaining agreements, Entergy Operations, Inc. agrees to provide plant level personnel from time to time from Entergy’s regulated utility nuclear power plants for the performance of field and maintenance services at the nuclear power plants owned by us and at third-party nuclear power plants to which EquaGen has agreed to provide services. In turn, EquaGen agrees, subject to certain conditions and to the terms of any applicable collective bargaining agreements, to provide plant level personnel from our nuclear power plants for the performance of field and maintenance services at Entergy’s regulated utility nuclear power plants.

Fees

In order to comply with certain settlements entered into by the Entergy regulated utility companies with their retail regulators, all services provided by EquaGen under the agreement will be charged the lower of fair market value or “fully allocated cost.” All services provided by Entergy Operations, Inc. will be charged “at fully allocated cost” plus 5%.

Term

The EquaGen Shared Services Agreement continues until the expiration of the last operating license that remains in effect for Entergy’s regulated utility nuclear power plants subject to certain rights of earlier termination.

Entergy Services, Inc. Shared Services Agreement

Under the Entergy Services, Inc. Shared Services Agreement, Entergy Services, Inc. will provide management and technical services to EquaGen.

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Provision of Support Services

The services to be provided are in the areas of operations support, administrative services, alliances, nuclear fuels procurement, materials, procurement and contracts, information technology, project management and engineering. Services under the Entergy Services, Inc. Shared Services Agreement may be provided directly or indirectly for the benefit of (i) EquaGen’s wholly-owned subsidiary, Entergy Nuclear Operations, or (ii) the owners or operators of third-party nuclear generating facilities to whom EquaGen or one of its subsidiaries has agreed to provide services.

Fees

In order to comply with certain settlements entered into by the Entergy regulated utility companies with their retail regulators, EquaGen is required to pay to Entergy Services, Inc. the “fully-allocated cost” of the services provided plus 5%.

Term

The Entergy Services, Inc. Shared Services Agreement continues until the expiration of the last operating license that remains in effect for the nuclear power plant facilities operated by EquaGen or its subsidiaries, subject to certain rights of earlier termination.

Entergy Services, Inc. Corporate Services Agreement

Under the Entergy Services, Inc. Corporate Services Agreement, Entergy Services, Inc. will provide corporate services to EquaGen.

Provision of Support Services

The services to be provided will be in such general corporate areas as human resources, treasury, accounting, information technology and tax. Services under the Entergy Services, Inc. Corporate Services Agreement may be provided directly or indirectly for the benefit of EquaGen’s wholly-owned subsidiary, Entergy Nuclear Operations.

Fees

Term

The agreement continues until the expiration of the last operating license that remains in effect for the nuclear power plant facilities operated by EquaGen or its subsidiaries, subject to certain rights of earlier termination.

Transition Services Agreement

We will enter into a transition services agreement with Entergy in connection with the separation. We refer to this agreement in this information statement as the “Transition Services Agreement.” Under the Transition Services Agreement we and Entergy will agree to provide certain services to each other for a specified period following the separation. The services to be provided may include services regarding business continuity and management, facilities management, data archiving, including services relating to human resources and employee benefits, payroll, financial systems management, treasury and cash management, accounts payable services, telecommunications services and information technology services. The recipient of any services will generally pay an agreed-upon service charge and reimburse the provider any out-of-pocket expenses, including the cost of any third party consents required. In order to comply with certain settlements entered into by the Entergy regulated utility companies with their retail regulators, we are required to pay to Entergy the “fully allocated cost” of the services provided plus 5%.

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Tax Sharing Agreement

We will enter into a Tax Sharing Agreement with Entergy that generally will govern Entergy’s and our respective rights, responsibilities and obligations after the distribution with respect to taxes pre-separation, attributable to our operations, and the operations of our direct and indirect subsidiaries, whether or not such tax liability is reflected on a consolidated or combined tax return filed by Entergy. For additional information, see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition — Liquidity and Capital Resources — Tax Sharing Agreement — Post-Separation.”

Notwithstanding the foregoing, we expect that, under the Tax Sharing Agreement, we also generally will be responsible for any taxes imposed on Entergy that arise from the failure of the distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Code, to the extent that such failure to qualify is attributable to actions, events or transactions relating to our stock, assets or business, or a breach of the relevant representations or covenants made by us in the Tax Sharing Agreement. In addition, we generally will be responsible for % of any taxes that arise from the failure of the distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Code, if such failure is for any reason for which neither we nor Entergy is responsible. The Tax Sharing Agreement also is expected to impose restrictions on our and Entergy’s ability to engage in certain actions following our separation from Entergy and to set forth the respective obligations among us and Entergy with respect to filing of tax returns, the administration of tax contests, assistance and cooperation and other matters.

Employee Matters Agreement

We will enter into an Employee Matters Agreement with Entergy and EquaGen prior to the distribution that will govern the compensation and employee benefit obligations with respect to our current and former employees and those of Entergy and EquaGen. The Employee Matters Agreement will allocate liabilities and responsibilities relating to employee compensation and benefits plans and programs and other related matters in connection with the distribution including, without limitation, the treatment of outstanding Entergy equity awards, certain outstanding annual and long-term incentive awards, existing deferred compensation obligations and certain retirement and welfare benefit obligations. Entergy Nuclear Operations will continue to honor or (if necessary) assume all relevant collective bargaining agreements for employees providing services in respect of EquaGen (other than through a Shared Services Agreement or similar arrangement), including all compensation and benefit obligations contained in those agreements. Once we establish our own compensation and benefits plans, we reserve the right, consistent with applicable contractual and statutory obligations, to amend, modify or terminate each such plan in accordance with the terms of that plan. With certain exceptions, the Employee Matters Agreement will provide that as of the consummation of the separation, our employees and those of EquaGen will cease to be active participants in, and we and EquaGen will generally cease to be a participating employer in, the benefit plans and programs maintained by Entergy. As of such time, our employees will generally become eligible to participate in all of our applicable plans. In general, we will credit each of our employees with his or her service with Entergy prior to the distribution for all purposes under plans maintained by us, to the extent the corresponding Entergy plans give credit for such service and such crediting does not result in a duplication of benefits.

Except as specifically provided in the Employee Matters Agreement, Entergy will generally retain responsibility for, and will pay and be liable for, all wages, salaries, welfare, incentive compensation and employment-related obligations and liabilities with respect to obligations to our current employees for the period preceding the distribution, former employees not associated with our business and any current employees who are not otherwise transferred to employment with us in connection with the distribution (except to the extent those obligations are assumed by EquaGen). The Employee Matters Agreement may also provide for the transfer of assets and liabilities relating to the pre-distribution participation of our employees and former employees of our business in various Entergy retirement, welfare, incentive compensation and employee benefit plans from such plans to the applicable plans we adopt for the benefit of our employees. Other than the assets being transferred pursuant to the Employee Matters Agreement, no fees will be paid by any party to the other party under the Employee Matters Agreement.

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DESCRIPTION OF ENEXUS ENERGY STOCK

We have provided below a summary description of our capital stock. This description is not complete and is qualified in its entirety by the full text of our amended and restated certificate of incorporation and by-laws which have been filed as exhibits to the registration statement into which this information statement is incorporated. You should read the full text of our amended and restated certificate of incorporation and by-laws, as well as the provisions of applicable Delaware law.

General

The total number of authorized shares of capital stock of Enexus Energy will consist of shares of common stock, par value $0.01 per share, and shares of preferred stock, par value $0.01 per share.

Common Stock

Voting Rights

Holders of our common stock are entitled to one vote for each share held by them on all matters submitted to our shareholders. Holders of our common stock do not have cumulative voting rights in the election of directors. Generally, all matters to be voted on by stockholders, including the election of directors, must be approved by a majority of the votes entitled to be cast by the holders of common stock present in person or represented by proxy, voting together as a single class, subject to any voting rights granted to holders of any preferred stock.

Dividend Rights

Holders of our common stock will share equally on a per share basis in any dividend declared by our board of directors out of funds legally available for that purpose, subject to any preferential rights of holders of any outstanding shares of preferred stock.

Other Rights

Upon voluntary or involuntary liquidation, dissolution or winding up of our company, after payment in full of the amounts required to be paid to creditors and holders of any preferred stock that may be then outstanding, all holders of common stock are entitled to share equally on a pro rata basis in all remaining assets.

No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of common stock or other securities of our company. There are no other subscription rights or conversion rights and there are no sinking fund provisions applicable to our common stock.

Upon completion of the distribution, all the outstanding shares of common stock will be validly issued, fully paid and nonassessable.

Amendment of By-laws

Except as otherwise provided by law, our certificate of incorporation or our by-laws, our by-laws may be amended, altered or repealed at a meeting of the stockholders provided that notice of such amendment, alteration or appeal is contained in the notice of such meeting or a meeting of our board of directors.

All such amendments must be approved by either the holders of a majority of the common stock or by a majority of the entire board of directors then in office.

Amendment of the Certificate of Incorporation

Any proposal to amend, alter, change or repeal any provision of our certificate of incorporation, except as may be provided in the terms of any preferred stock, requires approval by the affirmative vote of both a majority of the members of our board then in office and a majority vote of the voting power of all of the shares of our capital stock entitled to vote generally in the election of directors, voting together as a single class.

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Special Meeting

A special meeting of stockholders may be called by the board of directors or by any other person authorized to do so in the certificate of incorporation or the by-laws. Our charter provides that special meetings of stockholders may be called only by our board of directors, the chairman of our board, the person, if any, designated by our board of directors as the chief executive officer of our company, or by a majority of the members of the entire executive committee of our board of directors, if there shall be one.

Certain Anti-takeover Effects

General

Provisions of our certificate of incorporation and Delaware law could make it more difficult to consummate an acquisition of control of us by means of a tender offer, a proxy fight, open market purchases or otherwise in a transaction not approved by our board of directors. The provisions described below may reduce our vulnerability to an unsolicited proposal for the restructuring or sale of all or substantially all of our assets or an unsolicited takeover attempt that is unfair to our stockholders. The summary of the provisions set forth below does not purport to be complete and is qualified in its entirety by reference to our certificate of incorporation, or certificate of incorporation, and Delaware law.

Our board of directors has no present intention to introduce additional measures that might have an anti-takeover effect; however, our board of directors expressly reserves the right to introduce these measures in the future.

Business Combinations

We are governed by Section 203 of the General Corporation Law of the State of Delaware (DGCL). Section 203, subject to certain exceptions, prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the time that such stockholder became an interested stockholder, unless:


	•	prior to such time, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder; or

	•	upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding specified shares; or

	•	at or subsequent to such time, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder. The stockholders cannot authorize the business combination by written consent.

The application of Section 203 may limit the ability of stockholders to approve a transaction that they may deem to be in their best interests.

In general, Section 203 defines “business combination” to include:


	•	any merger or consolidation involving the corporation and the interested stockholder;

	•	any sale, lease, exchange, mortgage, pledge, transfer or other disposition of 10% or more of the assets of the corporation to or with the interested stockholder;

	•	subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any of its stock to the interested stockholder;

	•	any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or

	•	the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an “interested stockholder” as any person that is:


	•	the owner of 15% or more of the outstanding voting stock of the corporation;

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	•	an affiliate or associate of the corporation who was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately prior to the relevant date; or

	•	the affiliates and associates of the above.

Under specific circumstances, Section 203 makes it more difficult for an “interested stockholder” to effect various business combinations with a corporation for a three-year period, although the stockholders may, by adopting an amendment to the corporation’s certificate of incorporation or by-laws, elect not to be governed by this section, effective 12 months after adoption.

Our certificate of incorporation and by-laws do not exclude us from the restrictions imposed under Section 203. We anticipate that the provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board of directors since the stockholder approval requirement would be avoided if a majority of the directors then in office approve either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder.

Undesignated Preferred Stock

Our board of directors has the authority, without action by our stockholders, to designate and issue our preferred stock in one or more series and to designate the rights, preferences and privileges of each series, which may be greater than the rights of our common stock. It is not possible to state the actual effect of the issuance of any shares of our preferred stock upon the rights of holders of our common stock until our board of directors determines the specific rights of the holders of our preferred stock. However, the effects might include, among other things:


	•	restricting distributions to shareholders;

	•	diluting the voting power of our common stock;

	•	impairing the liquidation rights of our common stock; or

	•	delaying or preventing a change in control of our company without further action by our stockholders.

At the closing of the distribution, no shares of our preferred stock will be outstanding, and we have no present plans to issue any shares of preferred stock.

Classified Board of Directors

Our certificate of incorporation provides for our board to be divided into three classes of directors, as nearly equal in number as possible, serving staggered terms. Approximately one-third of our board will be elected each year. Under Section 141 of the DGCL, directors serving on a classified board can only be removed for cause. The provision for our classified board may be amended, altered, or repealed upon the affirmative vote of the holders of at least a majority of the voting power of the shares entitled to vote at an election of directors, or by a majority of the entire Board of Directors then in office.

The provision for a classified board could prevent a party that acquires control of a majority of the outstanding voting stock from obtaining control of our board until the second annual shareholders meeting following the date the acquiror obtains the controlling stock interest. The classified board provision could have the effect of discouraging a potential acquiror from making a tender offer for our shares or otherwise attempting to obtain control of us and could increase the likelihood that our incumbent directors will retain their positions.

We believe that a classified board will help to assure the continuity and stability of our board and our business strategies and policies as determined by our board, because a majority of the directors at any given time will have prior experience on our board. The classified board provision should also help to ensure that our board, if confronted with an unsolicited proposal from a third party that has acquired a block of our voting stock, will have sufficient time to review the proposal and appropriate alternatives and to seek the best available result for all stockholders.

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We expect that Class I directors will have an initial term expiring on the date of the 2009 annual meeting, Class II directors will have an initial term expiring on the date of the 2010 annual meeting and Class III directors will have an initial term expiring on the date of the 2011 annual meeting. After the separation, we expect our board will consist of directors.

After the initial term of each class, our directors will serve three-year terms. At each annual meeting of stockholders, a class of directors will be elected for a three-year term to succeed the directors of the same class whose terms are then expiring.

Our by-laws further provide that, generally, vacancies or newly created directorships in our board may only be filled by the vote of a majority of our board provided that a quorum is present and any director so chosen will hold office until the next election of the class for which such director was chosen.

Requirements for Advance Notification of Stockholder Nominations and Proposals

Our amended and restated by-laws establish advance notice procedures with respect to stockholder proposals and nomination of candidates for election as directors.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is BNY Mellon Shareowner Services.

Listing

We intend to file an application to list our shares of common stock on the New York Stock Exchange. We expect that our shares will trade under the ticker symbol .

Limitation of liability of directors and indemnification of directors and officers

We are a corporation organized under the laws of the State of Delaware. Section 102(b)(7) of the DGCL permits a corporation to provide in its certificate of incorporation that a director of the corporation shall not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability for any breach of the director’s duty of loyalty to the corporation or its stockholders, for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, for unlawful payments of dividends or unlawful stock repurchases, redemptions or other distributions or for any transaction from which the director derived an improper personal benefit.

Section 145 of the DGCL provides that a corporation has the power to indemnify a director, officer, employee or agent of the corporation and certain other persons serving at the request of the corporation in related capacities against amounts paid and expenses incurred in connection with an action or proceeding to which he is or is threatened to be made a party by reason of such position, if such person shall have acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the corporation, and, in any criminal proceeding, if such person had no reasonable cause to believe his conduct was unlawful; provided that, in the case of actions brought by or in the right of the corporation, no indemnification shall be made with respect to any matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the adjudicating court determines that such indemnification is proper under the circumstances.

Our certificate of incorporation provides that our directors shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director to the fullest extent permitted by the DGCL. Our certificate of incorporation further provides that we shall indemnify our directors and officers to the fullest extent authorized or permitted by the DGCL, and such right to indemnification shall continue as to a person who has ceased to be a director or officer of ours and shall inure to the benefit of his or her heirs, executors and administrators. The right to indemnification conferred by our certificate of incorporation also includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding in advance of its final disposition. Our by-laws provide, to the extent authorized from time to time by the board of directors, rights to indemnification to our employees and agents who are not directors or officers similar to those conferred to our directors and officers.

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DESCRIPTION OF MATERIAL INDEBTEDNESS

151

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form 10 with the SEC with respect to the shares of our common stock that Entergy shareholders will receive in the distribution. This information statement is a part of that registration statement and, as allowed by SEC rules, does not include all of the information you can find in the registration statement or the exhibits to the registration statement. For additional information relating to our company, the distribution and the separation, reference is made to the registration statement and the exhibits to the registration statement. Statements contained in this information statement as to the contents of any contract or document referred to are not necessarily complete and in each instance, if the contract or document is filed as an exhibit to the registration statement, we refer you to the copy of the contract or other document filed as an exhibit to the registration statement. Each such statement is qualified in all respects by reference to the applicable contract or document.

After the Form 10, of which this information statement is a part, is declared effective, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. We intend to furnish our shareholders with annual reports containing consolidated financial statements audited by an independent registered public accounting firm. The registration statement is, and any of these future filings with the SEC will be, available to the public over the Internet on the SEC’s website at http://www.sec.gov. You may read and copy any filed document at the SEC’s public reference room in Washington, D.C. at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1 (800) SEC-0330 for further information about the public reference room.

We maintain an Internet site at http://www.enexusenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated into this information statement or the registration statement on Form 10 of which this information statement is a part.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Management of Entergy Corporation and Subsidiaries, owner of Entergy Nuclear:

We have audited the accompanying combined balance sheets of Entergy Nuclear (non-utility nuclear businesses of Entergy Corporation and Subsidiaries as defined in Note 1) (the “Company”) as of December 31, 2007 and 2006, and the related combined income statements, combined statements of shareholders’ net investment and comprehensive income, and combined statements of cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the financial position of Entergy Nuclear as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

New Orleans, Louisiana

May 8, 2008

F-2

COMBINED INCOME STATEMENTS


	For the Years Ended December 31,
	2007			2006			2005
	(In Thousands)

OPERATING REVENUES

Operating Revenues		$2,029,666			$1,544,873			$1,421,547


OPERATING EXPENSES

Operation and Maintenance:
Fuel and fuel-related expenses		168,860			141,026			132,796
Nuclear refueling outage expenses		105,885			91,457			88,688
Other operation		645,903			534,208			506,754
Maintenance		138,480			117,742			106,714
Depreciation and amortization		99,265			71,755			58,540
Decommissioning expense		78,607			35,537			33,202
Taxes other than income taxes		78,550			62,285			53,797

TOTAL		1,315,550			1,054,010			980,491


OPERATING INCOME		714,116			490,863			441,056

OTHER INCOME

Interest and dividend income		102,842			83,161			66,840
Miscellaneous - net		(715	)		(427	)		(1,504	)

TOTAL		102,127			82,734			65,336

INTEREST EXPENSE

Interest expense to associated companies		103,450			90,958			72,230
Interest expense - other		14,722			17,530			18,476

TOTAL		118,172			108,488			90,706


INCOME BEFORE INCOME TAXES		698,071			465,109			415,686

Income taxes		212,023			188,318			160,328


NET INCOME		$486,048			$276,791			$255,358

See Notes to Combined Financial Statements.

F-3

COMBINED BALANCE SHEETS
ASSETS


	December 31,
	2007		2006
	(In Thousands)

CURRENT ASSETS

Cash and cash equivalents:
Cash		$3,726		$9,207
Temporary cash investments - at cost, which approximates market		425,133		374,602

Total cash and cash equivalents		428,859		383,809

Accounts receivable - customer		197,440		141,864
Materials and supplies - at average cost		234,527		193,849
Deferred nuclear refueling outage costs		127,523		80,770
Prepayments and other		39,663		16,733

TOTAL		1,028,012		817,025

OTHER PROPERTY AND INVESTMENTS

Decommissioning trust funds		1,937,601		1,583,847
Other		3,064		2,995

TOTAL		1,940,665		1,586,842

PROPERTY, PLANT, AND EQUIPMENT

Electric plant		2,971,825		1,937,449
Construction work in progress		189,574		173,897
Nuclear fuel		510,907		354,402

TOTAL PROPERTY, PLANT, AND EQUIPMENT		3,672,306		2,465,748
Less - accumulated depreciation and amortization		309,308		214,931

PROPERTY, PLANT, AND EQUIPMENT - NET		3,362,998		2,250,817

DEFERRED DEBITS AND OTHER ASSETS

Decommissioning contract		466,326		444,967
Payments in lieu of property taxes		202,971		219,776
Other		17,147		32,627

TOTAL		686,444		697,370


TOTAL ASSETS		$7,018,119		$5,352,054

See Notes to Combined Financial Statements.

F-4

COMBINED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY


	December 31,
	2007		2006
	(In Thousands)

CURRENT LIABILITIES

Currently maturing long-term debt		$28,056		$88,241
Loans payable - associated companies		1,256,627		868,815
Accounts payable:
Associated companies		125,093		69,101
Other		217,475		207,374
Taxes accrued		-		3,030
Pension and other post-retirement liabilities		3,613		2,904
Fair value of derivative instruments		-		162,639
Palisades purchased power agreement		76,223		-
NYPA value sharing accrual		72,000		-
Other		8,423		5,711

TOTAL		1,787,510		1,407,815

NON-CURRENT LIABILITIES

Accumulated deferred income taxes and taxes accrued		780,741		522,256
Decommissioning		1,141,552		773,348
Pension and other postretirement liabilites		313,581		284,726
Payments in lieu of property taxes		158,619		173,715
Long-term debt		210,732		237,553
Palisades purchased power agreement		293,060		-
Other		29,741		12,813

TOTAL		2,928,026		2,004,411


Commitments and Contingencies

SHAREHOLDERS’ EQUITY

Shareholders’ net investment		2,208,440		1,958,076
Accumulated other comprehensive income (loss)		94,143		(18,248	)

TOTAL		2,302,583		1,939,828


TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$7,018,119		$5,352,054

See Notes to Combined Financial Statements.

F-5

COMBINED STATEMENTS OF CASH FLOWS


	For the years ended December 31,
	2007			2006			2005
	(In Thousands)

OPERATING ACTIVITIES:
Net income	$	486,048		$	276,791		$	255,358
Adjustments to reconcile combined net income to net cash flow provided by operating activities:
Amortization of nuclear fuel		133,117			107,929			100,828
Amortization of Palisades purchased power agreement		(50,216	)		-			-
Accretion of decommissioning contract		(21,359	)		(20,380	)		(19,447	)
Depreciation, amortization, and decommissioning		177,872			107,292			91,742
Deferred income taxes and non-current taxes accrued		258,485			298,457			(160,183	)
Changes in working capital:
Accounts receivable		(55,576	)		(7,588	)		(4,441	)
Accounts payable		66,093			89,537			10,801
Prepaid taxes and taxes accrued		(3,030	)		139,252			161,124
Deferred nuclear refueling outage costs		(46,753	)		11,978			(16,854	)
Other working capital accounts		(60,896	)		42,214			(18,106	)
Other		(46,001	)		(237,853	)		159,880

Net cash flow provided by operating activities		837,784			807,629			560,702

INVESTING ACTIVITIES:
Construction/capital expenditures		(259,977	)		(302,865	)		(161,149	)
Palisades acquisition		(336,211	)		-			-
Nuclear fuel purchases		(225,684	)		(100,015	)		(164,564	)
Proceeds from nuclear decommissioning trust fund sales		1,293,369			503,498			503,983
Investment in nuclear decommissioning trust funds		(1,354,893	)		(550,837	)		(546,766	)

Net cash flow used in investing activities		(883,396	)		(450,219	)		(368,496	)

FINANCING ACTIVITIES:
Loans from associated companies		342,549			34,901			70,573
Loan repayments to associated companies		(7,737	)		(93,861	)		(76,897	)
Capital contributions from owners		15,465			44,568			12,173
Long-term debt repayments		(87,006	)		(75,897	)		(72,415	)
Returns of capital and dividends		(172,609	)		(95,653	)		(53,366	)

Net cash flow provided by (used in) financing activities		90,662			(185,942	)		(119,932	)

Net increase in cash and cash equivalents		45,050			171,468			72,274

Cash and cash equivalents at beginning of period		383,809			212,341			140,067


Cash and cash equivalents at end of period	$	428,859		$	383,809		$	212,341

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of capitalized interest	$	89,277		$	89,961		$	51,996
Income taxes	$	71,355		$	(69,601	)	$	3,950

Non-cash capital returns to owners	$	76,640		$	-		$	-
Non-cash debt incurred	$	-		$	28,531		$	-

See Notes to Combined Financial Statements.

F-6

COMBINED STATEMENTS OF SHAREHOLDERS’ NET INVESTMENT
AND COMPREHENSIVE INCOME


	For the Years Ended December 31,
	2007		2006		2005
	(In Thousands)

SHAREHOLDERS’ NET INVESTMENT

Shareholders’ Net Investment - Beginning of period	$1,958,076		$1,732,370		$1,518,205
Combined net income	486,048	$486,048	276,791	$276,791	255,358	$255,358
Capital contributions from owners	15,465		44,568		12,173
Capital returns and dividends to owners	(249,249)		(95,653)		(53,366)
FIN 48 implementation	(1,900)		-		-

Shareholders’ Net Investment - End of period	$2,208,440		$1,958,076		$1,732,370


ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Balance at beginning of period:
Accumulated derivative instrument fair value changes	($100,510)		($389,402)		($146,475)
Pension and other postretirement liabilities	(22,290)		(3,235)		(773)
Net unrealized investment gains	104,552		67,099		51,201

Total	(18,248)		(325,538)		(96,047)


Net derivative instrument fair value changes arising during the period (net of tax expense (benefit) of $57,120, $187,410 and ($151,917))	94,301	94,301	288,892	288,892	(242,927)	(242,927)
Pension and other postretirement liabilities (net of tax expense (benefit) of $11,766, ($29,777), and ($1,691))	1,031	1,031	(19,055)	3,235	(2,462)	(2,462)
Net unrealized investment gains (net of tax expense of $23,562, $28,428, and $10,573)	17,059	17,059	37,453	37,453	15,898	15,898
Balance at end of period:
Accumulated derivative instrument fair value changes	(6,209)		(100,510)		(389,402)
Pension and other postretirement liabilities	(21,259)		(22,290)		(3,235)
Net unrealized investment gains	121,611		104,552		67,099

Total	$94,143		($18,248)		($325,538)

Comprehensive Income		$598,439		($606,371)		$25,867

See Notes to Combined Financial Statements.

F-7

NOTES TO COMBINED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The combined financial statements of Entergy Nuclear (the Company) present the stand alone financial position, results of operations, and cash flows of Entergy’s Non-Utility Nuclear segment and Entergy Nuclear Finance Holdings, a wholly-owned Entergy subsidiary that provides financing to Entergy’s Non-Utility Nuclear business. The Company owns six operating nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. The Company’s power plants have nearly 5,000 megawatts of generating capacity, most of which is located in the northeastern United States. Entergy intends to distribute its ownership interest in the Company to Entergy’s shareholders in a spin-off transaction.

The combined financial statements are comprised of companies included in Entergy’s combined financial statements and accounting records, using their historical basis of assets and liabilities. Intercompany accounts and transactions have been eliminated in the combined financial statements.

Use of Estimates in the Preparation of Financial Statements

In conformity with generally accepted accounting principles, the preparation of the Company’s combined financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Revenue Recognition

The Company derives almost all of its revenue from sales of electric power generated by the six nuclear power plants that it owns. The Company recognizes revenue from electric power sales when it delivers power to its customers.

Property, Plant, and Equipment

Property, plant, and equipment is stated at cost. Depreciation is computed on the straight-line basis over the estimated remaining service lives of the plants, which as of December 31, 2007 was 24 years for Pilgrim, 26 years for FitzPatrick, 25 years for Indian Point 2, 27 years for Indian Point 3, 24 years for Vermont Yankee, and 23 years for Palisades, which assumes or takes into account renewal of the original operating licenses. Nuclear fuel is amortized using a units-of-production method. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses.

Capitalized Interest

Capitalized interest represents the costs of funds used for capital construction projects. These costs are capitalized as part of the cost of the project and are expensed over the life of the asset through depreciation.

Nuclear Refueling Outage Costs

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.

F-8

Notes to Financial Statements

Income Taxes

Entergy Corporation and the majority of its subsidiaries, including all of the Company’s entities, file a consolidated federal income tax return. Federal income taxes have been provided by Nuclear Power Company on the basis of its separate company income and deductions in accordance with established practices of the consolidated tax group under Entergy’s intercompany tax allocation agreement. In accordance with the intercompany tax allocation agreement, each company is responsible for its separate company tax. To the extent a company has a taxable loss that is utilized by other members of the consolidated return group, the loss company is reimbursed for the use of its loss.

In accordance with SFAS 109, “Accounting for Income Taxes,” deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.

Payments in Lieu of Property Taxes

The State of New York enacted property tax legislation during 2001 allowing taxing authorities to enter into long-term payments in lieu of tax (PILOT) agreements with nuclear plants. The Company subsequently entered into PILOT agreements with the local taxing jurisdictions in conformity with the property tax legislation. Under these agreements, the Company made long-term payments that have been recognized as prepayments. The Company is making specified fixed annual PILOT payments through 2014. The Company has recorded the net present value of the agreement obligations as non-current liabilities and has recorded a related deferred asset in order to properly recognize the expenses associated with these agreements.

Stock-based Compensation Plans

The Company participates in Entergy’s employee compensation plans. Entergy grants stock options to key employees of the Company, which is described more fully in Note 8 to the financial statements. Effective January 1, 2003, the Company prospectively adopted the fair value based method of accounting for stock options prescribed by SFAS 123, “Accounting for Stock-Based Compensation.” Awards under Entergy’s plans vest over three years.

Cash and Cash Equivalents

The Company considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.

Investments

The Company applies the provisions of SFAS 115, “Accounting for Investments for Certain Debt and Equity Securities,” in accounting for investments in decommissioning trust funds. As a result, the Company records the decommissioning trust funds at their fair value on the balance sheet. Unrealized gains and losses recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale unless an unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment has suffered an other than temporary impairment is based on a number of factors including, first, whether the Company has the ability and intent to hold the investment to recover its value and, then, whether it is expected that the investment will recover its value within a reasonable period of time. See Note 12 to the financial statements for details on the decommissioning trust funds.

F-9

Notes to Financial Statements

Decommissioning Liabilities

The Company records liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. Substantially all of the Company’s asset retirement obligations consist of its liability for decommissioning its nuclear power plants. These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. See Note 5 to the financial statements for additional information regarding decommissioning liabilities.

Decommissioning Contract

For the Indian Point 3 and FitzPatrick plants purchased in 2000 from the Power Authority of New York (NYPA), NYPA retained the decommissioning trusts and the decommissioning liability until 2017, at which time NYPA is expected to put its decommissioning liability to the Company in exchange for transferring a defined amount into the Company’s decommissioning trust funds for those units. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. These agreements are discussed further in Note 5 to the financial statements. The Company recorded an asset representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning cost estimated in an independent decommissioning cost study. The asset is increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion is recorded as interest income.

Derivative Financial Instruments and Commodity Derivatives

SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” requires that all derivatives be recognized in the balance sheet, either as assets or liabilities, at fair value, unless they meet the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.

Contracts for commodities that will be delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, are not classified as derivatives. These contracts are exempted under the normal purchase, normal sales criteria of SFAS 133. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

For other contracts for commodities in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portions of all hedges are recognized in current-period earnings.

The Company has determined that contracts to purchase uranium do not meet the definition of a derivative under SFAS 133 because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and the Company begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with the Company’s other derivative instruments.

F-10

Notes to Financial Statements

Fair Values

The estimated fair values of the Company’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The Company considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.

Impairment of Long-Lived Assets

The Company periodically reviews long-lived assets whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flow expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. The Company presents these taxes on a net basis, excluding them from revenues.

New Accounting Pronouncements

In September 2006 the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 generally does not require any new fair value measurements. However, in some cases, the application of SFAS 157 in the future may change the Company’s practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. SFAS 157 is effective for the Company in the first quarter 2008 and will be applied prospectively. Application of SFAS 157 did not materially affect the Company’s financial position, results of operations, or cash flows.

The FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) during the first quarter 2007. SFAS 159 provides an option for companies to select certain financial assets and liabilities to be accounted for at fair value with changes in the fair value of those assets or liabilities being reported through earnings. The intent of the standard is to mitigate volatility in reported earnings caused by the application of the more complicated fair value hedging accounting rules. Under SFAS 159, companies can select existing assets or liabilities for this fair value option concurrent with the effective date of January 1, 2008 for companies with fiscal years ending December 31 or can select future assets or liabilities as they are acquired or entered into. Adoption of this standard did not have a material effect on the Company’s financial position, results of operations, or cash flows.

F-11

Notes to Financial Statements


NOTE 2.	INCOME TAXES

Income tax expenses from continuing operations for 2007, 2006, and 2005 for the Company consist of the following:


	2007			2006			2005
	(In Thousands)

Current:
Federal		($92,482	)		$634,921			$64,752
State		(45,149	)		32,480			14,313

Total		(137,631	)		667,401			79,065
Deferred - net:
Federal		322,626			(518,082	)		69,522
State		27,044			38,999			11,741

Total		349,670			(479,083	)		81,263
Investment tax credit adjustments - net		(16	)		-			-

Income tax expense		$212,023			$188,318			$160,328

F-12

Notes to Financial Statements

Total income taxes from continuing operations for the Company differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for 2007, 2006, and 2005 are:


	2007	2006	2005
	(In Thousands)

Combined net income	$486,048	$276,791	$255,358
Income taxes	212,023	188,318	160,328

Pretax income	$698,071	$465,109	$415,686

Computed at statutory rate (35%)	$244,325	$162,788	$145,490
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	(4,836)	20,066	6,947
Decommissioning trust fund basis	(35,684)	-	-
Permanent differences	(7,383)	2,964	(3,106)
Tax reserves	10,900	2,000	-
Other - net	4,701	500	10,997

Total income taxes	$212,023	$188,318	$160,328

Effective Income Tax Rate	30.4%	40.5%	38.6%

Significant components of net deferred and noncurrent accrued tax liabilities for the Company and subsidiaries as of December 31, 2007 and 2006 are as follows:


	2007	2006
	(In Thousands)

Deferred and Noncurrent Accrued Tax Liabilities:
Plant-related basis differences	($711,540)	($953,568)
Power purchase agreements	(465,403)	(1,042,182)
Nuclear decommissioning trusts	(430,908)	(522,954)
Other	(106,973)	(59,178)

Total	(1,714,824)	(2,577,882)


Deferred Tax Assets:
Net operating loss carryforwards	403,235	1,552,202
Power purchase agreements	133,810	-
Deferred revenues	4,226	-
Pension-related items	137,790	133,033
Nuclear decommissioning liabilities	240,590	313,522
Other	14,432	56,869

Total	934,083	2,055,626


Net deferred and noncurrent accrued tax liability	($780,741)	($522,256)

At December 31, 2007, the Company had estimated federal net operating loss carryforwards of $1,121 million primarily resulting from changes in tax accounting methods relating to a 2005 mark-to-market tax accounting election. The tax accounting method change produces temporary book tax differences, which will reverse in the

F-13

Notes to Financial Statements

future. If the federal net operating loss carryforwards are not utilized, they will expire in the years 2023 through 2027.

At December 31, 2007, the Company had estimated state net operating loss carryforwards of $558.4 million, primarily resulting from the 2005 mark-to-market tax accounting election. If the state net operating loss carryforwards are not utilized, they will expire in the years 2010 through 2017.

For 2007 and 2006, valuation allowances are provided against federal and state capital loss carryforwards, and certain state net operating loss carryforwards.

On March 13, 2007, the Vermont Department of Taxes issued Technical Bulletin 35 explaining the Department of Taxes’ interpretation of the treatment of net operating losses under Vermont’s 2005, Act 207 (Act 207) which required unitary combined reporting effective January 1, 2006. On January 7, 2008, the Vermont Department of Taxes issued Technical Bulletin 40 explaining the Department of Taxes’ interpretation of the conversion of federal net operating losses to Vermont net operating losses under Act 207. The guidance in Technical Bulletin 35 was utilized to determine that Entergy would have approximately $272 million of Vermont net operating loss available to offset future Vermont taxable income. The Company believes that its estimate determined under Technical Bulletin 35 is materially accurate. After evaluating Technical Bulletin 40, the Company believes that Technical Bulletin 40 has no effect on the amount recorded related to its Vermont net operating loss carryover.

Income Tax Audits and Litigation

Entergy and its subsidiaries file income tax returns in the federal and various state and foreign jurisdictions. With few exceptions, as discussed below, Entergy is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by taxing authorities for years before 2004.

Entergy entered into an agreement with the IRS Appeals Division in the second quarter 2007 to partially settle tax years 1999 - 2001. Entergy will litigate the following issue that affects the Company that it is not settling:


	•	The allowance of depreciation deductions and/or other deductions and basis that resulted from Entergy’s purchase price allocations on its acquisitions of its nuclear power plants - the Company expects that the total tax to be included in IRS Notices of Deficiency already issued and to be issued in the future on this issue will be $34 million. The federal and state tax and interest associated with this issue total $40 million for all open tax years.

On February 21, 2008, the IRS issued the Statutory Notice of Deficiency relative to the above issues. As stated above, Entergy will pursue this issue in court.

The IRS completed its examination of the 2002 and 2003 tax returns and issued an Examination Report on June 29, 2007.

In the report for the 2002-2003 audit cycle, the IRS proposed adjustments related to the Company which Entergy did not agree to as follows: 1) deductions claimed for research and experimentation (R&E) expenditures; 2) income tax credits claimed for R&E; and 3) a 2003 deduction associated with the revisions to the emergency plans at the Indian Point Energy Center. Regarding all of these issues, Entergy disagrees with the IRS Examination Division position and filed a formal protest on July 30, 2007 with the IRS and will pursue administrative relief within the IRS Appeals Division.

The IRS commenced an examination of Entergy’s 2004 and 2005 U.S. income tax returns in the fourth quarter 2007. As of December 31, 2007, the IRS has not proposed any adjustments to Entergy’s computation of tax for those years, however, it is anticipated that to the extent that the issues in litigation and those raised in the prior audit cycles continue into 2004 and 2005, the IRS will propose similar adjustments.

The Company has $51 million in deposits on account with the IRS to cover its uncertain tax positions.

F-14

Notes to Financial Statements

FASB Interpretation No. 48

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48) was issued in June 2006. FIN 48 establishes a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. The Company adopted the provisions of FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized an increase in the liability for unrecognized tax benefits of approximately $2 million, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. A reconciliation of the Company’s beginning and ending amount of unrecognized tax benefits is as follows (in thousands):


Balance at January 1, 2007 upon implementation		$803,903
Additions based on tax positions related to the current year		92,001
Additions for tax positions of prior years		165,751
Reductions for tax positions of prior years		(276,203)
Settlements		(10,601)
Lapse of statute of limitations		(136)

Balance at December 31, 2007		$774,715

Included in the above December 31, 2007 balance of unrecognized tax benefits are $0.7 billion of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the effect of deferred tax accounting, other than on interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company’s December 31, 2007 balance of unrecognized tax benefits includes $39 million which could affect the effective income tax rate. The Company accrues interest and penalties expenses related to unrecognized tax benefits in income tax expense. The Company’s December 31, 2007 balance of unrecognized tax benefits includes approximately $8.5 million accrued for the possible payment of interest and penalties.

The Company does not expect that total unrecognized tax benefits will significantly change within the next twelve months; however, the results of audit settlements and pending litigation could result in changes to this total. The Company is unable to predict or quantify any changes at this time.

F-15

Notes to Financial Statements


NOTE 3.	LOANS PAYABLE - ASSOCIATED COMPANIES AND LONG-TERM DEBT

Loans payable - associated companies and long-term debt for the Company as of December 31, 2007 and 2006 consisted of:


	Amounts Outstanding
	2007		2006
	(In Thousands)

Loans Payable - associated companies:
$400 million available, expires March 2012		$352,381		$350,913
$691.5 million available, expires September 2011		1,283		9,020
$200 million available, expires February 2008		136,972		136,972
$120 million available, expires December 2009		115,483		114,436
$225 million available, expires October 2009		195,068		193,222
Advance from Entergy Corporation, non-interest bearing		72,440		64,252
$32 million loan, due February 2008		32,000		-
$21 million note, due July 2008, 8% interest rate		21,000		-
Entergy Corporation credit facility indebtedness		330,000		-

Total Loans Payable - associated companies		$1,256,627		$868,815


Long-Term Debt:
Payable to NYPA, non-interest bearing, 4.8% implicit rate		$217,751		$297,290
Other long-term debt, non-interest bearing, 7.0% implicit rate		21,037		28,504

Total Long-Term Debt		238,788		325,794
Less Amount Due Within One Year		28,056		88,241

Long-Term Debt Excluding Amount Due Within One Year		$210,732		$237,553

The loans payable - associated companies are owed to Entergy or its subsidiaries and are due on demand. Except as noted above, the loans accrue interest at variable rates that are tied to the London Interbank Offering Rate (LIBOR). The average rate accrued for interest on these notes was 7.58% in 2007 and 7.20% in 2006. The carrying value of the Company’s loans payable - associated companies is a reasonable estimate of its fair value because of the variable interest rates on those loans.

Entergy Corporation drew on its revolving credit facility in April 2007 and sent $330 million of the proceeds to the Company as part of the funding for the Palisades power plant acquisition. The Company reflects the proceeds received from Entergy Corporation as debt rather than as an equity contribution because the proceeds were used in the operations of the Company and proceeds of the Company debt that will be issued in connection with the spinoff of the Company are expected to be used to repay the Entergy Corporation revolver indebtedness. Interest is accrued at a variable rate tied to LIBOR, which rate averaged 7.58% in 2007.

In November 2000, the Company purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. The Company notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in the Company becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003. This liability was recorded upon the purchase of Indian Point 2 in September 2001, and is included in the note

F-16

Notes to Financial Statements

payable to NYPA balance above. In July 2003, a payment of $102 million was made prior to maturity on the note payable to NYPA.

The annual maturities for long-term debt outstanding as of December 31, 2007, for the next five years are as follows:


	Amount
	(In Thousands)

2008	$	28,056
2009	$	29,480
2010	$	29,966
2011	$	30,961
2012	$	28,203


NOTE 4.	COMMITMENTS AND CONTINGENCIES

The Company is involved in a number of legal, regulatory, and tax proceedings before various courts and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on the Company’s results of operations, cash flows, or financial condition. The Company discusses tax proceedings in Note 2 to the financial statements.

Nuclear Insurance

Third Party Liability Insurance


	1.	The primary level is private insurance underwritten by American Nuclear Insurers and provides public liability insurance coverage of $300 million. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies.

	2.	Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, up to a maximum of $100.6 million per reactor per incident. This consists of a $95.8 million maximum retrospective premium plus a five percent surcharge that may be payable, if needed, at a rate that is presently set at $15 million per year per nuclear power reactor. There are no terrorism limitations.

The Company owns and operates six nuclear power reactors and owns the shutdown Indian Point 1 reactor and the Big Rock Point fuel facility.

Property Insurance

The Company’s nuclear owner/licensee companies are members of certain mutual insurance companies that provide property damage coverage, including decontamination and premature decommissioning expense, to the

F-17

Notes to Financial Statements

members’ nuclear generating plants. These programs are underwritten by Nuclear Electric Insurance Limited (NEIL). As of December 31, 2007, the Company was insured against such losses per the following structures:


	•	Primary Layer (per plant) - $500 million per occurrence

	•	Excess Layer - $615 million per occurrence

	•	Total limit - $1.115 billion per occurrence

	•	Deductibles:


	•	$2.5 million per occurrence - Turbine/generator damage

	•	$2.5 million per occurrence - Other than turbine/generator damage

Note: Indian Point 2 (including Indian Point 1) and Indian Point 3 share in the Primary and Excess Layers with one policy in common for that site because the policy is issued on a per site basis. The Big Rock Point fuel facility has its own Primary policy with no excess coverage.

In addition, the power plants are also covered under NEIL’s Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible. The following summarizes this coverage as of December 31, 2007:

Indian Point 2 & 3 and Palisades (Indian Point 2 & 3 share the limits)


	•	$4.5 million weekly indemnity

	•	$490 million maximum indemnity

	•	Deductible: 12 week waiting period

FitzPatrick and Pilgrim (each plant has an individual policy with the noted parameters)


	•	$4.0 million weekly indemnity

	•	$490 million maximum indemnity

	•	Deductible: 12 week waiting period

Vermont Yankee


	•	$4.0 million weekly indemnity

	•	$435 million maximum indemnity

	•	Deductible: 12 week waiting period

Under the property damage and accidental outage insurance programs, the Company’s nuclear power plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. As of December 31, 2007, the maximum amount of such possible assessments per occurrence was $86.8 million for the Company.

The Company maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

F-18

Notes to Financial Statements

indemnity, and any other sources applicable to such losses. There is no aggregate limit involving one or more acts of certified terrorism.

NYPA Value Sharing Agreements

The purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, the Company and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements the Company will make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. The Company will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year is due by January 15 of the following year, with the payment for year 2007 output due on January 15, 2008. If Entergy or an Entergy affiliate ceases to own the plants, then, after January 2009, the annual payment obligation terminates for generation after the date that Entergy ownership ceases. Therefore, after the spin-off transaction, the Company does not expect to make value sharing payments to NYPA, other than for 2008 generation, assuming the spin-off transaction is completed as expected in 2008.

The Company will record its liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. The Company recorded a $72 million liability for generation through December 31, 2007. An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.

The Company had previously calculated that $0 was owed to NYPA under the value sharing agreements for generation output in 2005 and 2006. In November 2006, NYPA filed a demand for arbitration claiming that $90.5 million was due to NYPA for 2005 under these agreements, and NYPA filed in April 2007 an amended demand for arbitration claiming that an additional $54 million was due to NYPA for 2006 under the value sharing agreements. As part of their agreement to amend the value sharing agreements, the Company and NYPA waived all present and future claims under the previous value sharing terms, including the claims for 2005 and 2006 pending before the arbitrator.

Employment and Labor-related Proceedings

The Company is responding to lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsored plans. Entergy and the Company are responding to these suits and proceedings and deny liability to the claimants.


NOTE 5.	ASSET RETIREMENT OBLIGATIONS

The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2007 by the Company were as follows:


		Change in
Liabilities as of		Cash Flow		Liabilities as of
December 31, 2006 (a)	Accretion	Estimate	Spending	December 31, 2007
		(In Millions)

$993.0	$78.6	$100.4	($30.4)	$1,141.6


(a)		The liability as of December 31, 2006 includes $219.7 million for the Palisades nuclear plant which was acquired in April 2007.

F-19

Notes to Financial Statements

The Company periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 2007, 2006, and 2005 the Company updated decommissioning cost estimates for certain of its plants.

In the fourth quarter 2007, the Company recorded an increase of $100 million in decommissioning liabilities for certain of its plants as a result of revised decommissioning cost studies. The revised estimates resulted in the recognition of a $100 million asset retirement obligation asset that will be depreciated over the remaining life of the units.

In the third quarter 2006, the Company recorded a reduction of $27 million in decommissioning liability for a plant as a result of a revised decommissioning cost study and changes in assumptions regarding the timing of when decommissioning of the plant will begin. The revised estimate resulted in reduced expenses of $27 million ($16.6 million net-of-tax), reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143 in 2003.

In the first quarter 2005, the Company recorded a reduction of $26.0 million in its decommissioning cost liability in conjunction with a new decommissioning cost study as a result of revised decommissioning costs and changes in assumptions regarding the timing of the decommissioning of a plant. The revised estimate resulted in reduced expenses of $26.0 million ($15.8 million net-of-tax), reflecting the excess of the reduction in the liability over the amount of undepreciated asset retirement cost recorded at the time of adoption of SFAS 143 in 2003.

For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability. NYPA and Entergy executed decommissioning agreements, which specify their decommissioning obligations. Beginning in 2017, NYPA has the right to require the Company to assume the decommissioning liability provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Company. If the decommissioning liability is retained by NYPA, the Company will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The Company believes that the amounts available to it under either scenario are sufficient to cover the future decommissioning costs without any additional contributions to the trusts. See Note 1 to the financial statements for a discussion of the accounting treatment of these contracts.

The Company maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The total fair value of the decommissioning trust funds of the Company as of December 31, 2007 is $1,937.6 million.

F-20

Notes to Financial Statements

NOTE 7. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS

Qualified Pension Plans and Other Postretirement Benefit Plans

Eligible employees of the Company are provided pension and certain health care and life insurance benefits upon retirement. Substantially all employees may become eligible for these benefits if they reach retirement age while working for the Company.

Eligible employees of the Company participate in one of six qualified pension plans: Entergy Corporation Retirement Plan for Non-Bargaining Employees, Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan III,” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining Employees.” Except for “Entergy Corporation Retirement Plan III,” the pension plans are noncontributory and provide pension benefits that are based on employees’ credited service and compensation during the final years before retirement. Funding for these qualified pension costs are in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the qualified plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees.

In September 2006, FASB issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements Nos. 87, 88, 106 and 132(R),” which was effective December 31, 2006. SFAS 158 requires an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Employers are to record previously unrecognized gains and losses, prior service costs, and the remaining transition asset or obligation as a result of adopting SFAS 87 and SFAS 106 as accumulated other comprehensive income (OCI). SFAS 158 also requires that changes in the funded status be recorded in other comprehensive income in the period in which the changes occur. The Company uses a December 31 measurement date for its pension plans.

F-22

Notes to Financial Statements

Total 2007 and 2006 qualified pension and other postretirement costs for the Company including capitalized amounts, included the following components:


	Qualified Pension									Other Postretirement Benefits
	2007			2006			2005			2007			2006			2005
	(In Thousands)

Net periodic pension and other postretirement costs
Service cost		$29,761			$28,754			$26,433			$15,591			$17,498			$15,259
Interest cost		26,169			22,040			18,855			10,787			11,393			9,296
Expected return on assets		(25,235	)		(21,217	)		(15,720	)		(1,706	)		(1,363	)		(1,380	)
Amortization of prior service cost		887			887			279			(11,212	)		(6,399	)		(5,918	)
Recognized net loss		1,963			3,394			3,051			2,598			4,413			3,197
Curtailment loss		2,336			-			-			-			-			-
Special termination benefit loss		928			-			-			111			-			-

Net costs		$36,809			$33,858			$32,898			$16,169			$25,542			$20,454

Other changes in plan assets and benefit obligations recognized as a OCI (before tax)
Arising this period:
Prior services cost		$11,340									($3,520	)
Net gain		(17,598	)								(11,941	)
Amounts reclassified from accumulated OCI to net periodic pension cost in the current year:
Amortization of prior service credit		(887	)								11,212
Amortization of net gain		(1,963	)								(2,598	)

Total		(9,108	)								($6,847	)

Total recognized as net periodic pension cost, and/or OCI (before tax)
		$27,701									$9,322

Estimated amortization amounts from accumulated OCI to net periodic cost in the following year
Prior service cost		$1,946									($11,793	)
Net loss		$906									$1,594

F-23

Notes to Financial Statements


	Qualified Pension						Other Postretirement Benefits
	2007			2006			2007			2006
	(In Thousands)

Change in Projected Benefit Obligation (PBO)/Accumulated Postretirement Obligation (APBO)
Balance at beginning of year		$410,328			$376,274			$173,821			$195,857
Service cost		29,761			28,754			15,591			17,498
Interest cost		26,169			22,040			10,787			11,393
Acquisitions and amendments		52,143			-			7,816			(30,910	)
Curtailments		2,603			-			-			-
Special termination benefits		928			-			111			-
Employee contributions		971			1,002			4			239
Actuarial gain		(21,599	)		(12,084	)		(12,337	)		(16,690	)
Benefits paid		(7,032	)		(5,658	)		(3,005	)		(3,576	)
Medicare Part D subsidy received		-			-			58			10

Balance at end of year		$494,272			$410,328			$192,846			$173,821

Change in Plan Assets
Fair value of assets at beginning of year		$287,908			$203,722			$20,419			$19,579
Actual return on plan assets		21,235			29,810			1,310			2,408
Employer contributions		35,251			59,032			967			1,769
Employee contributions		971			1,002			4			239
Acquisition		21,731			-			5,114			-
Benefits paid		(7,032	)		(5,658	)		(3,005	)		(3,576	)

Fair value of assets at end of year		$360,064			$287,908			$24,809			$20,419

Funded status		($134,208	)		($122,420	)		($168,037	)		($153,402	)


	Qualified Pension						Other Postretirement Benefits
	2007			2006			2007			2006

Amounts recognized in the balance sheet (funded status under SFAS 158)
Non-current asset		$5,783			$-			$-			$-
Current liabilities		-			-			(3,344	)		(2,720	)
Non-current liabilities		(139,991	)		(122,420	)		(164,693	)		(150,682	)

Funded status		($134,208	)		($122,420	)		($168,037	)		($153,402	)


Amounts recognized in OCI (before tax)
Prior service cost		$7,815			$8,704			($46,149	)		($53,842	)
Net loss		36,783			44,736			33,822			48,362

		$44,598			$53,440			($12,327	)		$5,480

F-24

Notes to Financial Statements

In 2007, 2006, and 2005, the affiliate billings to the Company, as described in Note 13, included qualified pension costs of $3.2 million, $2.1 million, and $1.4 million, respectively and other postretirement benefit costs of $1.7 million, $1.1 million, and $0.8 million, respectively.

Qualified Pension and Other Postretirement Plans’ Assets

The Company’s qualified pension and postretirement plans’ weighted-average asset allocations by asset category at December 31, 2007 and 2006 are as follows:


	Qualified Pension						Postretirement
	2007			2006			2007			2006

Domestic Equity Securities		44	%		43	%		37	%		37	%
International Equity Securities		20	%		21	%		14	%		14	%
Fixed-Income Securities		34	%		34	%		49	%		49	%
Other		2	%		2	%		-	%		-	%

The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long-term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.

In the optimization study, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.

The optimization analysis utilized in the Plan Administrator’s latest study produced the following approved asset class target allocations.


	Pension			Postretirement

Domestic Equity Securities		45	%		37	%
International Equity Securities		20	%		14	%
Fixed-Income Securities		31	%		49	%
Other (Cash and Group Annuity Contracts)		4	%		0	%

These allocation percentages combined with each asset class’ expected investment return produced an aggregate return expectation for the five years following the study of 7.6% for pension assets, 5.4% for taxable postretirement assets, and 7.2% for non-taxable postretirement assets.

The expected long term rate of return of 8.50% for the qualified Retirement Plans assets is based on the expected long-term return of each asset class, weighted by the target allocation for each class as defined in the table above. The source for each asset class’ expected long-term rate of return is the geometric mean of the respective asset class total return. The time period reflected in the total returns is a long dated period spanning several decades.

The expected long term rate of return of 8.50% for the non-taxable VEBA trust assets is based on the expected long-term return of each asset class, weighted by the target allocation for each class as defined in the table above. The source for each asset class’ expected long-term rate of return is the geometric mean of the respective asset class total return. The time period reflected in the total returns is a long dated period spanning several decades.

F-25

Notes to Financial Statements

For the taxable VEBA trust assets the allocation has a high percentage of tax-exempt fixed income securities. The tax-exempt fixed income long-term total return was estimated using total return data from the 2007 Economic Report of the President. The time period reflected in the tax-exempt fixed income total return is 1929 to 2006. After reflecting the tax-exempt fixed income percentage and unrelated business income tax, the long-term rate of return for taxable VEBA trust assets is expected to be 6.0%.

Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable economically efficient plan to manage to targets:


	Pension	Postretirement

Domestic Equity Securities	45% to 55%	32% to 42%
International Equity Securities	15% to 25%	9% to 19%
Fixed-Income Securities	25% to 35%	44% to 54%
Other	0% to 10%	0% to 5%

Accumulated Qualified Pension Benefit Obligation

The accumulated qualified pension benefit obligation for the Company as of December 31, 2007 and 2006 was $379.7 million and $310.3 million, respectively.

Estimated Future Benefit Payments

Based upon the assumptions used to measure the Company’s pension and postretirement benefit obligation at December 31, 2007, and including pension and postretirement benefits attributable to estimated future employee service, the Company expects that pension and other postretirement benefits to be paid over the next ten years are as follows (in thousands):


	Estimated Future Benefit Payments
					Other
					Postretirement		Estimated Future
	Qualified		Non-Qualified		(before Medicare		Medicare Subsidy
Year(s)	Pension		Pension		Subsidy)		Receipts


2008		$9,629		$268		$5,569		$148
2009		$11,501		$268		$6,475		$204
2010		$13,306		$268		$7,650		$265
2011		$15,367		$268		$9,046		$350
2012		$18,917		$268		$10,577		$461
2013 - 2017		$158,328		$1,342		$80,352		$4,934

Contributions

In 2008, the Company expects to contribute $44 million (including $1 million in participant contributions) to the qualified pension plans and $3.4 million to the other postretirement plans.

F-26

Notes to Financial Statements

Actuarial Assumptions

The assumed health care cost trend rate used in measuring the APBO of the Company was 9% for 2008, gradually decreasing each successive year until it reaches 4.75% in 2013 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of the Company was 10% for 2007, gradually decreasing each successive year until it reaches 4.5% in 2012 and beyond. A one percentage point change in the assumed health care cost trend rate for 2007 would have the following effects:


1 Percentage Point Increase		1 Percentage Point Decrease
	Impact on the		Impact on the
	sum of service		sum of service
Impact on the	costs and	Impact on the	costs and
APBO	interest cost	APBO	interest cost
Increase (Decrease)
(In Thousands)

$27,526	$4,703	($23,834)	($3,918)

The significant actuarial assumptions used in determining the pension PBO and the SFAS 106 APBO as of December 31, 2007, and 2006 were as follows:


	2007			2006

Weighted-average discount rate:
Pension		6.50	%		6.00	%
Other postretirement		6.50	%		6.00	%
Weighted-average rate of increase in future compensation levels		4.23	%		3.25	%

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2007, 2006, and 2005 were as follows:


	2007			2006			2005

Weighted-average discount rate:
Pension		6.00	%		5.90	%		6.00	%
Other postretirement		6.00	%		5.90	%		6.00	%
Weighted-average rate of increase in future compensation levels		3.25	%		3.25	%		3.25	%
Expected long-term rate of return on plan assets:
Taxable assets		5.50	%		5.50	%		5.50	%
Non-taxable assets		8.50	%		8.50	%		8.50	%

Medicare Prescription Drug, Improvement and Modernization Act of 2003

In December 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 into law. The Act introduces a prescription drug benefit cost under Medicare (Part D), starting in 2006, as well as federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.

The actuarially estimated effect of future Medicare subsidies reduced the Company’s December 31, 2007 and 2006 Accumulated Postretirement Benefit Obligation by $26.7 million and $24.3 million, respectively, and reduced the 2007 and 2006 other postretirement benefit cost by $4.4 million and $4.7 million, respectively. In 2007, the Company received $58 thousand in Medicare subsidies for prescription drug claims through June 2007.

F-27

Notes to Financial Statements

Non-Qualified Pension Plans

Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain executives. The Company recognized net periodic pension cost of $1.4 million in 2007 and $1.3 million in 2006. The projected benefit obligation was $14.8 million and $11.8 million as of December 31, 2007 and 2006, respectively. The accumulated benefit obligation was $12.3 million and $10.8 million as of December 31, 2007 and 2006, respectively

The Company’s non-qualified, non-current liability at December 31, 2007 and 2006, after application of SFAS 158, was $14.5 million and $11.7 million, respectively; and its current liability was $0.3 million and $0.2 million, respectively. The unamortized transition asset, prior service cost, and net loss recognized in accumulated other comprehensive income before taxes was $8.9 million at December 31, 2007 and $6.4 million at December 31, 2006.

In 2007, 2006, and 2005, the affiliate billings to the Company, as described in Note 13, included non-qualified pension costs of $2.1 million, $1.7 million, and $2.1 million, respectively.

Defined Contribution Plans

Employees of the Company are also eligible to participate in the Savings Plans of Entergy Corporation and Subsidiaries (Savings Plans). The Savings Plans are defined contribution plans covering eligible employees. The employing company makes matching contributions to the Savings Plans for all non-bargaining and certain bargaining employees to the System Savings Plans as defined in the Plan Documents. The Company’s contributions to the Savings Plans were $10.0 million in 2007 and $8.7 million in 2006.

F-28

Notes to Financial Statements


NOTE 8.	STOCK-BASED COMPENSATION

Certain employees of the Company participate in Entergy’s stock-based compensation plans, including its stock option grants, long-term incentive awards, and restricted awards.

Stock Options

Entergy Corporation has granted stock options to purchase its common stock to the Company employees at exercise prices equivalent to the closing market price of Entergy Corporation’s common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised.

The following table includes financial information for stock options granted to the Company’s employees for each of the years presented:


	2007		2006		2005

Compensation expense included in Net Income		$3.1		$1.8		$2.2
Tax benefit recognized in Net Income		$1.4		$0.8		$1.0
Compensation cost capitalized as part of fixed assets and inventory as of December 31,		$0.4		$0.3		$0.3

The fair value of the stock option grants made in 2007, 2006, and 2005 was determined by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability. The fair value valuations comply with SFAS 123R, “Share-Based Payment,” which was issued in December 2004 and became effective in the first quarter 2006. The stock option weighted-average assumptions used in determining the fair values are as follows:


	2007		2006		2005

Stock price volatility		17.0%		18.7%		18.8%
Expected term in years		4.57		3.8		3
Risk-free interest rate		4.9%		4.4%		4.0%
Dividend yield		3.0%		3.2%		3.1%
Dividend payment		$2.16		$2.16		$2.16

Stock price volatility was calculated based upon the weekly public stock price volatility of Entergy Corporation common stock over the last four to five years. The expected term of the options was based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options. Options held by certain management level employees include a restriction that requires 75% of the gains upon exercise of the option to be held in Entergy Corporation common stock until the earlier of five years or termination of employment. The reduction in fair value of the stock options because of this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the five year reinvestment period.

F-29

Notes to Financial Statements

A summary of stock option activity for stock options granted to the Company employees for the years ended December 31, 2005, 2006, and 2007 and changes during the years are presented below:


	2007					2006					2005
				Weighted-					Weighted-					Weighted-
				Average					Average					Average
	Number			Exercise		Number			Exercise		Number			Exercise
	of Options			Price		of Options			Price		of Options			Price

Beginning-of-year balance		1,742,778			$55.24		1,664,402			$50.80		1,719,502			$44.94

Options granted		360,700			$91.82		319,500			$68.92		303,500			$69.47
Options exercised		(236,863	)		$55.34		(241,124	)		$42.77		(357,400	)		$40.91
Options forfeited/expired		(2,367	)		$69.08		-			-		(1,200	)		$58.60


End-of-year balance		1,864,248			$62.29		1,742,778			$55.24		1,664,402			$50.80


Options exercisable at year-end		1,190,780			$51.54		1,111,793			$48.37		1,027,875			$44.30

Weighted-average grant-date fair value of options granted during the year		$14.12					$9.17					$8.17

The aggregate intrinsic value and weighted-average contractual life of options outstanding and options exercisable are as follows:

Aggregate

Weighted-

Number

Intrinsic

Average

of Options

Value

Contractual Life

2005:

Options outstanding

1,664,402

$69 million

6.0 years

Options exercisable

1,027,875

$49 million

5.3 years

2006:

Options outstanding

1,742,778

$65 million

6.7 years

Options exercisable

1,111,793

$49 million

5.7 years

2007:

Options outstanding

1,864,248

$107 million

6.3 years

Options exercisable

1,190,780

$81 million

5.1 years

The total intrinsic value of stock options exercised was $11.9 million during 2007, $8.6 million during 2006, and $11.2 million during 2005. The intrinsic value, which has no effect on net income, of the stock options exercised is calculated by the difference in Entergy’s Corporation common stock price on the date of exercise and the exercise price of the stock options granted. With the adoption of the fair value method of SFAS 123 and the application of SFAS 123R, the Company recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $2.8 million during 2007, $2.5 million during 2006, and $2.7 million during 2005.

F-30

Notes to Financial Statements

The following table summarizes information about stock options outstanding and stock options exercisable as of December 31, 2007:


		Options Outstanding						Options Exercisable
				Weighted-Avg.
				Remaining		Weighted-		Number		Weighted-
Range of		As of		Contractual		Avg. Exercise		Exercisable		Avg. Exercise
Exercise Prices		12/31/2007		Life-Yrs.		Price		at 12/31/2007		Price

	$23 - $36.99		10,399		2.9		$23.00		10,399		$23.00
	$37 - $50.99		653,185		4.1		$42.20		653,185		$42.20
	$51 - $64.99		262,412		5.7		$57.82		262,412		$57.82
	$65 - $78.99		577,552		7.4		$69.30		264,784		$69.48
	$79 - $91.82		360,700		9.1		$91.82		-		-

	$23 - $91.82		1,864,248		6.3		$62.29		1,190,780		$51.54

Stock-based compensation expense related to non-vested stock options outstanding as of December 31, 2007 not yet recognized is approximately $3.9 million and is expected to be recognized on a weighted-average period of 1.8 years.

The following table summarizes information about stock options outstanding and stock options exercisable as of December 31, 2006:


		Options Outstanding						Options Exercisable
				Weighted-Avg.
				Remaining		Weighted-		Number		Weighted-
Range of		As of		Contractual		Avg. Exercise		Exercisable		Avg. Exercise
Exercise Prices		12/31/2006		Life-Yrs.		Price		at 12/31/2006		Price

	$23 - $33.99		11,599		3.9		$23.00		11,599		$23.00
	$34 - $44.99		694,836		5.3		$41.97		694,836		$41.97
	$45 - $55.99		86,789		3.1		$49.01		86,789		$49.01
	$56 - $66.99		300,128		7.2		$58.60		191,027		$58.60
	$67 - $86.20		649,426		8.4		$69.30		127,542		$69.82

	$23 - $86.20		1,742,778		6.7		$55.24		1,111,793		$48.37

The following table summarizes information about stock options outstanding as of December 31, 2005:


		Options Outstanding						Options Exercisable
				Weighted-Avg.
				Remaining		Weighted-		Number		Weighted-
Range of		As of		Contractual		Avg. Exercise		Exercisable		Avg. Exercise
Exercise Prices		12/31/2005		Life-Yrs.		Price		at 12/31/2005		Price

	$23 - $33.99		18,283		3.6		$23.89		18,283		$23.89
	$34 - $44.99		894,672		5.2		$41.55		779,811		$41.12
	$45 - $55.99		86,789		3.1		$49.01		86,789		$49.01
	$56 - $66.99		325,539		7.2		$58.60		107,373		$58.60
	$67 - $86.20		339,119		7.8		$69.60		35,619		$69.67

	$23 - $86.20		1,664,402		6.0		$50.80		1,027,875		$44.30

F-31

Notes to Financial Statements

Long-Term Incentive Awards

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the end of the performance period, which is the last trading day of the year. Performance units will pay out to the extent that the performance conditions are satisfied. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the three-year performance period applicable to each plan. The costs of incentive awards are charged to income over the three-year period. The Company’s financial statements include its allocated share of costs for long-term incentive awards. The following table includes the approximate costs for the long-term incentive awards for each of the years presented:


	2007		2006		2005
	(In Millions)

Compensation expense included in Net Income for the year		$8.1		$3.8		$3.6
Tax benefit recognized in Net Income for the year		$3.8		$1.8		$1.7
Compensation cost capitalized as part of fixed assets and inventory as of December 31,		$1.1		$0.6		$0.5

Restricted Awards

Entergy grants restricted awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted units are equal to the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted awards granted is 52 months. The Company’s financial statements include its allocated share of costs for restricted awards. The following table includes the approximate costs for restricted awards for each of the years presented:


	2007		2006		2005
	(In Millions)

Compensation expense included in Net Income for the year		$0.5		$0.0		$3.2
Tax benefit recognized in Net Income for the year		$0.2		$0.0		$1.5
Compensation cost capitalized as part of fixed assets and inventory as of December 31,		$0.1		$0.0		$0.5


NOTE 9.	BUSINESS SEGMENT INFORMATION

The Company has one reportable segment, which is a business that owns and operates six nuclear power plants and is primarily focused on selling electric power produced by those plants to wholesale customers. This business is managed on an integrated basis.

For the years ended December 31, 2007, 2006, and 2005, the Company derived none of its revenue from outside of the United States. As of December 31, 2007 and 2006, the Company had no long-lived assets located outside of the United States.

F-32

Notes to Financial Statements


NOTE 10.	ACQUISITIONS

Palisades

In April 2007, the Company purchased the 798 MW Palisades nuclear energy plant located near South Haven, Michigan from Consumers Energy Company for a net cash payment of $336 million. The Company received the plant, nuclear fuel, inventories, and other assets. The liability to decommission the plant, as well as related decommissioning trust funds, was also transferred to the Company. The Company executed a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. In the first quarter 2007, the NRC renewed Palisades’ operating license until 2031. As part of the transaction, the Company assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Palisades’ financial results since April 2007 are included in the Company’s financial statements. The following table summarizes the assets acquired and liabilities assumed at the date of acquisition.


	Amount
	(In Millions)

Plant (including nuclear fuel)		$727
Decommissioning trust funds		252
Other assets		41

Total assets acquired		1,020

Purchased power agreement (below market)		420
Decommissioning liability		220
Other liabilities		44

Total liabilities assumed		684

Net assets acquired		$336

Subsequent to the closing, the Company received approximately $6 million from Consumers Energy Company as part of the Post-Closing Adjustment defined in the Asset Sale Agreement. The Post-Closing Adjustment amount resulted in an approximately $6 million reduction in plant and a corresponding reduction in other liabilities.

The Company will amortize the PPA liability to revenue over the life of the agreement. The amount that will be amortized each period is based upon the difference between the present value calculated at the date of acquisition of each year’s difference between revenue under the agreement and revenue based on estimated market prices. In 2007, $50 million was amortized to revenue. The amounts to be amortized to revenue for the next five years will be $76 million for 2008, $53 million for 2009, $46 million for 2010, $43 million for 2011, and $17 million in 2012.

Supplemental information on an unaudited pro forma basis, as if the Palisades acquisition were consummated at the beginning of the years 2007 and 2006, is as follows (in millions):


	2007		2006

Operating revenues	$	2,099	$	1,823
Net income	$	494	$	311

The unaudited pro forma supplemental information is based on estimates and assumptions, which management believes are reasonable; it is not necessarily indicative of the combined results of operations in future periods or the results that actually would have been realized had the Palisades acquisition occurred at the beginning of the years 2007 and 2006.

F-33

Notes to Financial Statements


NOTE 11.	RISK MANAGEMENT AND FAIR VALUES

Market and Commodity Risks

In the normal course of business, the Company is exposed to market and commodity risks including power price risk, fuel price risk, foreign currency exchange rate risk, and equity price and interest rate risk on investments. Market risk is the potential loss that the Company may incur as a result of changes in the market or fair value of a particular financial instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

The Company manages these risks through both contractual arrangements and derivatives. Contractual risk management tools include long-term power sales agreements and fuel purchase agreements, and capacity contracts. Commodity and financial derivative risk management tools can include electricity forwards, swaps, options, and foreign currency forwards. The Company enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.

The Company’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option’s contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which the Company is exposed is its use of hedging techniques to mitigate such risk. The Company manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. The Company’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given the Company’s objectives.

Hedging Derivatives

The Company classifies substantially all of its electricity futures, forwards, and options as cash flow hedges. Cash flow hedges with net unrealized gains of approximately $5.4 million (net-of-tax) at December 31, 2007 are scheduled to mature during 2008. Net losses totaling approximately $63 million were realized during 2007 on the maturity of cash flow hedges. Unrealized gains or losses result from hedging power output at the power stations. The related gains or losses from hedging power are included in revenues when realized. The realized gains or losses from foreign currency transactions are included in the cost of capitalized fuel because they relate to fuel acquisition. The maximum length of time over which the Company is currently hedging the variability in future cash flows for forecasted transactions at December 31, 2007 is approximately five years. The ineffective portion of the change in the value of the Company’s cash flow hedges during 2007, 2006, and 2005 was insignificant.

Fair Values

Financial Instruments

The estimated fair value of the Company’s financial instruments is determined using forward mid curves. These independent market curves are periodically compared to NYMEX Clearport prices where available and have been found to be materially identical. Additional adjustments for unit contingent discounts and/or price differentials between liquid market locations and plant busbars are internally determined and applied depending on settlement terms of the financial instrument. In determining these adjustments, the Company uses a process that estimates the forward values based on recent observed history. Due largely to the potential for market or product illiquidity, forward estimates are not necessarily indicative of the amounts that the Company could realize in a current market exchange.

The Company considers the carrying amounts of most of its financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.

F-34

Notes to Financial Statements


NOTE 12.	DECOMMISSIONING TRUST FUNDS

The Company holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires the Company to maintain trusts to fund the costs of decommissioning Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities; fixed-rate, fixed-income securities; and cash and cash equivalents. The securities held at December 31, 2007 and 2006 are summarized as follows:


			Total		Total
	Fair		Unrealized		Unrealized
	Value		Gains		Losses
	(In Millions)

2007
Equity Securities		$1,169		$218		$8
Debt Securities		769		22		1

Total		$1,938		$240		$9

2006
Equity Securities		$987		$189		$2
Debt Securities		597		8		4

Total		$1,584		$197		$6

The debt securities have an average coupon rate of approximately 5.2%, an average duration of approximately 5.5 years, and an average maturity of approximately 8.9 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor’s 500 Index, and a relatively small percentage of the securities are held in a fund intended to replicate the return of the Wilshire 4500 Index.

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2007:


	Equity Securities				Debt Securities
			Gross				Gross
	Fair		Unrealized		Fair		Unrealized
	Value		Losses		Value		Losses
	(In Millions)

Less than 12 months		$153		$8		$69		$1
More than 12 months		-		-		2		-

Total		$153		$8		$71		$1

The Company evaluates these unrealized losses at the end of each period to determine whether an other than temporary impairment has occurred. The assessment of whether an investment has suffered an other than temporary impairment is based on a number of factors including, first, whether the Company has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. The Company’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. The Company did not record any significant impairments in 2007 or 2006 on these assets.

F-35

Notes to Financial Statements

The fair value of debt securities, summarized by contractual maturities, at December 31, 2007 and 2006 are as follows:


	2007		2006
	(In Millions)

less than 1 year		$36		$38
1 year - 5 years		229		175
5 years - 10 years		255		213
10 years - 15 years		77		53
15 years - 20 years		50		44
20 years+		122		74

Total		$769		$597

During the years ended December 31, 2007, 2006, and 2005, proceeds from the dispositions of securities amounted to $1,293 million, $504 million, and $504 million, respectively. During the years ended December 31, 2007, 2006, and 2005, gross gains of $3.5 million, $3.1 million, and $3.2 million, respectively, and gross losses of $2.9 million, $7.7 million, and $4 million, respectively, were reclassified out of other comprehensive income into earnings.


NOTE 13.	TRANSACTIONS WITH AFFILIATES

See Note 3 to the financial statements for a description of loans payable by the Company to associated companies.

The Company receives management, administrative, accounting, legal, engineering, and other services from Entergy Services, Inc., indirectly through Entergy Enterprises, Inc., which are both wholly-owned subsidiaries of Entergy. The Company’s expenses for such services were $89.0 million in 2007, $52.3 million in 2006, and $41.9 million in 2005. These costs are allocated to the Company based on the actual costs incurred by Entergy Services and the extent that the activities related to or benefited the Company, whether directly or indirectly. Management believes that the cost allocations are reasonable for the services provided, and also believes that the cost allocations are consistent with the approximate amount of costs for these services that would have been incurred on a stand-alone basis.

Entergy Corporation or its wholly-owned subsidiaries have issued guarantees with stated amounts totalling approximately $1.9 billion for the performance or obligations of the Company’s business. Guarantees are provided primarily to satisfy the Company’s obligations to provide the following: collateral to secure its obligations under some of its power sale agreements; security for its obligations for retrospective premiums under the Price-Anderson Act; collateral for a letter of credit that supports its note payable to NYPA; and security for certain of its decommissioning obligations. Fees charged to the Company by Entergy Corporation for these guarantees are

F-36

Notes to Financial Statements

included in “Interest expense to associated companies” on the income statement and totaled $24.0 million in 2007, $30.4 million in 2006, and $22.7 million in 2005.


NOTE 14.	QUARTERLY FINANCIAL DATA (UNAUDITED)

Operating results for the four quarters of 2007 and 2006 for the Company were:


	Operating		Operating		Net
	Revenues		Income		Income
	(In Thousands)

2007:
First Quarter		$458,251		$201,569		$120,295
Second Quarter		$471,521		$156,742		$96,862
Third Quarter		$554,128		$211,658		$149,022
Fourth Quarter		$545,766		$144,147		$119,869

2006:
First Quarter		$388,010		$130,320		$74,964
Second Quarter		$362,362		$103,094		$56,655
Third Quarter		$409,431		$129,239		$98,733
Fourth Quarter		$385,070		$128,210		$46,439

Earnings were negatively affected in the fourth quarter 2007 by expenses of $29.9 million ($18.4 million net-of-tax) recorded in connection with a nuclear operations fleet alignment. This process was undertaken with the goals of eliminating redundancies, capturing economies of scale, and clearly establishing organizational governance. Most of the expenses related to the voluntary severance program offered to employees. Approximately 200 employees accepted the voluntary severance program offers.

F-37


	•	EBITDA does not reflect our cash expenditures, or future requirements for capital expenditures or contractual commitments;

	•	EBITDA does not reflect changes in, or cash requirements for, our working capital needs;

	•	EBITDA does not reflect interest expense, or the cash requirements necessary to service interest or principal payments on our indebtedness;

	•	Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized often will have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and

	•	Other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure.


	Options Awards
	Number
	of		Stock Awards
	Shares		Number of
	Acquired	Value	Shares	Value
	on	Realized	Acquired	Realized
	Exercise	on Exercise	on Vesting	on Vesting
Name	(#)	($)	(#)⁽¹⁾	($)
(a)	(b)	(c)	(d)	(e)

Richard J. Smith	-	$-	14,279	$1,706,626

John R. McGaha	18,900	$1,002,016	6,452	$771,143


(1)		Represents the vesting of performance units for the 2005 - 2007 performance period (payable solely in cash based on the closing stock price of Entergy on the date of vesting) under the Performance Unit Program.


Item	Page

Report of Independent Registered Public Accounting Firm		F-2
Combined Income Statements for the years ended December 31, 2007, 2006 and 2005		F-3
Combined Balance Sheets as of December 31, 2007 and 2006		F-4
Combined Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005		F-6
Combined Statements of Shareholders’ Net Investment and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005		F-7
Notes to Combined Financial Statements		F-8


	Operating
Year	Leases
	(In Thousands)

2008		$4,968
2009		4,762
2010		3,703
2011		2,870
2012		2,432
Years thereafter		3,912

Minimum lease payments		$22,647